UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For
the fiscal year ended
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission
File No.
(Exact name of registrant as specified in its charter)
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Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
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Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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by check-mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
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by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or and emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act:
Large
Accelerated Filer ☐ Accelerated Filer ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
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Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.1D-1(b). ☐
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by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐
The
aggregate market value of the voting stock held by non-affiliates of the Registrant as of September 30, 2022 (the last business day of
the Registrant’s most recently completed second quarter) was $
There were shares of the registrant’s common stock outstanding as of June 26, 2023.
DOCUMENTS INCORPORATED BY REFERENCE
TABLE OF CONTENTS
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As used in this document, “the Company”, “Mexco”, “we”, “us” and “our” refer to Mexco Energy Corporation and its consolidated subsidiaries.
Abbreviations or definitions of certain terms commonly used in the oil and gas industry and in this Form 10-K can be found in the “Glossary of Abbreviations and Terms”.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”). These forward-looking statements are generally located in the material set forth under the headings “Risk Factors”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Business”, “Properties” but may be found in other locations as well, and are typically identified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions.
Forward-looking statements generally relate to our profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations and are based upon our management’s reasonable estimates of future results or trends. Actual results in future periods may differ materially from those expressed or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including those discussed in “Risk Factors”. The factors that may affect our expectations regarding our operations include, among others, the following: our success in development, exploitation and exploration activities; our ability to make planned capital expenditures; declines in our production or prices of oil and gas; our ability to raise equity capital or incur additional indebtedness; our restrictive debt covenants; our acquisition and divestiture activities; weather conditions and events; the proximity, capacity, cost and availability of pipelines and other transportation facilities; increases in the cost of drilling, completion and gas gathering or other costs of production and operations; and other factors discussed elsewhere in this document. We disclaim any intention or obligation to update or revise any forward-looking statements as a result of new information, future events or otherwise.
PART I
ITEM 1. BUSINESS
General
Mexco Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the acquisition, exploration, development and production of crude oil and natural gas properties located in the United States. Incorporated in April 1972 under the name Miller Oil Company, the Company changed its name to Mexco Energy Corporation effective April 30, 1980. At that time, the shareholders of the Company also approved amendments to the Articles of Incorporation resulting in a one-for-fifty reverse stock split of the Company’s common stock.
Our total estimated proved reserves at March 31, 2023 were approximately 1.552 million barrels of oil equivalent (“MMBOE”) of which 47% was oil and natural gas liquids and 53% was natural gas, and our estimated present value of proved reserves was approximately $39 million based on estimated future net revenues excluding taxes discounted at 10% per annum, pricing and other assumptions set forth in “Item 2 – Properties” below.
Nicholas C. Taylor beneficially owns approximately 44% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations.
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Company Profile
Since our inception, we have been engaged in acquiring and developing oil and gas properties and the exploration for and production of natural gas, crude oil, condensate and natural gas liquids (“NGLs”) within the United States. We especially seek to acquire proved reserves that fit well with existing operations or in areas where Mexco has established production. Acquisitions preferably will contain most of their value in producing wells, behind pipe reserves and high quality proved undeveloped locations. Competition for the purchase of proved reserves is intense. Sellers often utilize a bid process to sell properties. This process usually intensifies the competition and makes it extremely difficult to acquire reserves without assuming significant price and production risks. We actively search for opportunities to acquire proved oil and gas properties. However, because the competition is intense, we cannot give any assurance that we will be successful in our efforts during fiscal 2024.
While we own oil and gas properties in other states, the majority of our activities are centered in West Texas and Southeastern New Mexico. The Company also owns producing properties and undeveloped acreage in fourteen states. We acquire interests in producing and non-producing oil and gas leases from landowners and leaseholders in areas considered favorable for oil and gas exploration, development and production. In addition, we may acquire oil and gas interests by joining in oil and gas drilling prospects generated by third parties. We may also employ a combination of the above methods of obtaining producing acreage and prospects. In recent years, we have placed primary emphasis on the evaluation and purchase of producing oil and gas properties, including working, royalty and mineral interests, and prospects that could have a potentially meaningful impact on our reserves. All of the Company’s oil and gas interests are operated by others.
From 1983 to 2023, Mexco Energy Corporation made numerous acquisitions of royalties, overriding royalties, minerals and working interests in producing oil and gas properties including the following most significant acquisitions:
| 1990-1994 | Royalty interests, aggregate purchase price of approximately $501,000 covering multiple wells in the Gomez (Ellenberger) Field of Pecos County, Texas. | |
| 1993-2014 | Tabbs Bay Oil Company and Thompson Brothers Lumber Company, respectively dissolved in 1957 and 1947. Purchase covering thousands of acres located respectively in 19 counties of Texas, 3 parishes of Louisiana and one county in Arkansas and 8 counties of Texas, respectively consisting of various mineral, royalty and overriding royalty interests. |
| 1997 | Forman Energy Corporation, purchase price of $1,591,000 consisting primarily of working interests in approximately 634 wells located in 12 states. |
| 2004 | Royalty interests, purchase price $304,000 covering 37 producing wells in the Cotton Valley formation in Limestone County, Texas and the Lower Cotton Valley formation in Jackson Parish, Louisiana. This acreage contains 13 permitted or drilling wells and approximately 100 potential undrilled locations. |
Royalty interests, purchase price $500,000 covering 4 producing gas units in Freestone County, Texas containing 33 producing wells and 17 potential undeveloped locations in the Cotton Valley formation.
| 2005 | Royalty interests, purchase price $550,000 covering 75 producing wells, 9 permitted and/or drilling wells, and 83 potential undeveloped locations in the Cotton Valley formation of Freestone and Limestone Counties, Texas. |
| 2007 | Non-operated working interests, purchase price $425,000 covering 2 properties in Lea County, New Mexico. |
Royalty (mineral) acreage, purchase price $1,850,000 covering 122 mineral acres in the Newark East (Barnett Shale) Field of Tarrant County, Texas amounting to approximately 21.45% royalty interest.
| 2008 | Royalty (mineral) acreage, purchase price $429,000 covering 522 mineral acres in the Newark East (Barnett Shale) Field of Tarrant County, Texas containing 6 producing natural gas wells, 5 proven undeveloped well locations, and 6 potential drill sites on this acreage. In March 2009, purchased additional interests, $49,000. |
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| 2010 | Southwest Texas Disposal Corporation, purchase price $478,000 consisting of royalty interests in over 300 wells located in 60 counties and parishes of 6 states. |
Overriding royalty interests, purchase price $1,650,000 covering 5,120 gross acres over 8 sections in the Haynesville trend area of DeSoto Parish, Louisiana containing 6 horizontal producing wells, 2 wells drilling wells, and 57 additional potential drill sites. The Company paid $1.46 million in cash and the remainder was paid as 26,833 shares of its common stock issued from treasury shares.
| 2011 | Non-operating working interests, purchase price $670,000 covering 160 gross acres in the Fuhrman-Mascho Field of Andrews County, Texas containing 5 producing wells in the Grayburg and San Andres formations and additional 11 potential drill sites. In March 2012, purchased additional working interests, $275,000. |
| 2012 | TBO Oil and Gas, LLC, purchase price of $1,150,000 consisting of working interests in approximately 280 wells located in 16 counties of 3 states. |
| 2014 | Royalty interests, purchase price $200,000 covering 43 wells in 12 counties of 8 states, primarily in Texas. |
Royalty interests, purchase price $580,000 covering 580 wells in 87 counties of 8 states. Approximately 90% of the net revenue from these royalties is produced by 157 wells located in the Barnett Shale of the Fort Worth Basin of Texas. Also included are interests in 423 wells in 8 states.
Royalty and mineral interests, purchase price $1,000,000 covering approximately 1,800 wells in 27 counties of Texas. Of these oil and gas reserves, approximately 80% is natural gas and 20% oil.
Non-Operated working interests, purchase price $840,000 in 70 Natural gas producing wells located in 5 counties of Oklahoma.
Non-Operated working interests, purchase price $200,000 covering 80 wells located in Hockley and Pecos Counties, Texas.
Non-Operated working interests, purchase price $450,000 covering 43 wells in Webster Parish, Louisiana; Eddy County, New Mexico; and, Nolan and Smith Counties, Texas.
| 2019 | Royalty interest investment, $300,000 for a less than 1% investment commitment in a limited liability company, capitalized at approximately $50 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. This LLC has returned $226,725 and 76% of the total investment since inception in fiscal 2020. |
| 2022-2023 | Overriding royalty interests, purchase price of $567,000 covering 53 producing wells and several additional potential locations for development in Atascosa and Karnes Counties, Texas. |
Royalty interests, purchase price of $939,000 covering 22 producing wells and several additional potential locations for development in the Eagleford area of Dimmit County, Texas.
Royalty interest investment, $2,000,000 for an approximate 2% investment commitment in a limited liability company, capitalized at approximately $100 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. As of the date of this report, $400,000 of the commitment has been expended.
Royalty interests, purchase price of $117,200 covering 28 producing wells in 6 counties in the Haynesville trend area of Louisiana and 5 counties in Texas.
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Industry Environment and Outlook
The outbreak of the novel coronavirus (“COVID-19”) resulted in a severe worldwide economic downturn, significantly disrupting the demand for oil throughout the world, and created significant volatility, uncertainty and turmoil in the oil and gas industry. The decrease in demand for oil, combined with excess supply of oil and related products, resulted in oil prices declining significantly in late February 2020. Since mid-2020, oil prices have improved, with demand steadily increasing despite the uncertainties surrounding the COVID-19 variants, which have continued to inhibit a full global demand recovery. In addition, worldwide oil inventories, from a historical perspective, remain low and concerns exist with the ability of Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing nations to meet forecasted future oil demand growth in 2023 and 2024, with many OPEC countries not able to produce at their OPEC agreed upon quota levels due to their limited capital investments, and increases in cost over the last few years directed towards developing incremental oil supplies.
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion of our fiscal 2023 operating results and potential impact on fiscal 2024 operating results due to commodity price changes.
Oil and Gas Operations
As of March 31, 2023, oil constituted approximately 70% of our oil and gas revenues and approximately 47% of our total proved reserves volumes for fiscal 2023. Revenues from oil and gas royalty interests accounted for approximately 28% of our oil and gas revenues for fiscal 2023.
There are two primary areas in which the Company is focused, 1) the Delaware Basin located in the Western portion of the Permian Basin including Lea and Eddy Counties, New Mexico and Reeves and Loving Counties, Texas and 2) the Midland Basin located in the Eastern portion of the Permian Basin including Reagan, Upton, Midland, Martin, Howard and Glasscock Counties, Texas. The Permian Basin in total accounts for 80% of our discounted future net cash flows from proved reserves and 79% of our gross revenues.
The Permian Basin is one of the oldest and most prolific producing basins in North America which has been a significant source of oil production since the 1920s. The Permian Basin is known to have a number of zones of oil and natural gas bearing rock throughout.
The Delaware Basin properties, encompassing 30,007 gross acres, 195 net acres, 610 gross producing wells and 4 net wells account for approximately 58% of our discounted future net cash flows from proved reserves as of March 31, 2023. For fiscal 2023, these properties accounted for 62% of our net revenues. Of these discounted future net cash flows from proved reserves, approximately 15% are attributable to proven undeveloped reserves which would be developed through new drilling.
The Midland Basin properties, encompassing 97,584 gross acres, 256 net acres, 1,016 gross producing wells and 2 net wells account for approximately 18% of our discounted future net cash flows from proved reserves as of March 31, 2023. For fiscal 2023, these properties accounted for 14% of our net revenues. Of these discounted future net cash flows from proved reserves, approximately 8% are attributable to proven undeveloped reserves which would be developed through new drilling.
Mexco believes its most important properties for future development by horizontal drilling and hydraulic fracturing area are located in Lea and Eddy Counties, New Mexico of the Delaware Basin and the Midland Basin in Midland, Reagan and Upton Counties, Texas.
For more on these and other operations in this area see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources Commitments”.
We own partial interests in approximately 6,400 producing wells all of which are located within the United States in the states of Texas, New Mexico, Oklahoma, Louisiana, Alabama, Mississippi, Arkansas, Wyoming, Kansas, Colorado, Montana, Virginia, North Dakota, and Ohio. Additional information concerning these properties and our oil and gas reserves is provided below.
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The following table indicates our oil and gas production in each of the last five years:
| Year | Oil(Bbls) | Gas (Mcf) | ||||||
| 2023 | 73,968 | 534,363 | ||||||
| 2022 | 61,689 | 393,841 | ||||||
| 2021 | 50,327 | 324,205 | ||||||
| 2020 | 44,301 | 294,007 | ||||||
| 2019 | 35,359 | 295,133 | ||||||
Competition and Markets
The oil and gas industry is a highly competitive business. Competition for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed at a competitive disadvantage. Competitive factors include price, contract terms and types and quality of service, including pipeline distribution. The price for oil and gas is widely followed and is generally subject to worldwide market factors. Our ability to acquire and develop additional properties in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment in a timely manner.
In addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue.
Market factors affect the quantities of oil and natural gas production and the price we can obtain for the production from our oil and natural gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental, energy conservation and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry.
The market for our oil, gas and natural gas liquids production depends on factors beyond our control including: domestic and foreign political conditions; the overall level of supply of and demand for oil, gas and natural gas liquids; the price of imports of oil and gas; weather conditions; the price and availability of alternative fuels; the proximity and capacity of gas pipelines and other transportation facilities; and overall economic conditions.
Major Customers
We made sales that amounted to 10% or more of oil and gas revenues as follows for the years ended March 31:
| 2023 | 2022 | |||||||
| Company A | 53 | % | 68 | % | ||||
Historically, the Company has not experienced significant credit losses on our oil and gas accounts and management is of the opinion that significant credit risk does not exist. Because a ready market exists for oil and gas production, we do not believe the loss of any individual purchaser would have a material adverse effect on our financial position or results of operations.
Environmental Regulation
The oil and gas industry is extensively regulated at the federal, state, and local levels. Regulations affecting elements of the energy sector are under constant review for amendment or expansion and frequently more stringent requirements are imposed. Various federal and state agencies, including the Texas Railroad Commission, the Bureau of Land Management (the “BLM”), an agency of the U.S Department of the Interior (“DOI”), the Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection Agency (the “EPA”), the Department of Transportation (“DOT”) and the U.S. Occupational Safety and Health Administration (“OSHA”), have legal and regulatory authority and oversight over the operations on the properties in which the Company owns an interest.
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Under certain environmental laws and regulations, the operators of the Company properties could be subject to strict, joint and several liability for the removal or remediation of property contamination, whether at a drill site or a waste disposal facility, even when the operators did not cause the contamination or their activities were in compliance with all applicable laws at the time the actions were taken. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, for example, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons for releases into the environment of a “hazardous substance.” Liable persons may include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who arranged for the disposal of a hazardous substance at a site. Under CERCLA and similar statutes, government authorities or private parties may take actions in response to threats to the public health or the environment or sue responsible persons for the associated costs. In the course of operations, the working interest owner and/or the operator of the Company properties may have generated and may generate materials that could trigger cleanup liabilities. In addition, the Company properties have produced oil and/or natural gas for many years, and previous operators may have disposed or released hydrocarbons, wastes or hazardous substances at the Company properties. The operator of the Company properties or the working interest owners may be responsible for all or part of the costs to clean up any such contamination. Although the Company is not the operator of such properties, its ownership of the properties could cause it to be responsible for all or part of such costs to the extent CERCLA or any similar statute imposes responsibility on such parties as “owners.”
Various state governments and regional organizations comprising state governments already have enacted legislation and promulgated rules restricting greenhouse gases (“GHGs”) emissions or promoting the use of renewable energy, and additional such measures are frequently under consideration. Although it is not possible at this time to estimate how potential future requirements addressing GHG emissions would impact operations on the Company properties and revenue, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions could require the operators of our properties to incur new or increased costs to obtain permits, operate and maintain equipment and facilities, install new emission controls, acquire allowances to authorize GHG emissions, pay taxes related to GHG emissions or administer a GHG emissions program. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas. Additionally, to the extent that unfavorable weather conditions are exacerbated by global climate change or otherwise, the Company properties may be adversely affected to a greater degree than previously experienced.
We did not incur any material capital expenditures for remediation or pollution control activities for the year ended March 31, 2023. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during fiscal 2024.
Other Regulation
Other agencies with certain authority over the Company’s business include the Internal Revenue Service (the “IRS”), the SEC and NYSE. Ensuring compliance with the rules, regulations and orders promulgated by such entities requires extensive effort and incremental costs to comply, which affects the Company’s profitability. Because public policy changes are commonplace, and existing laws and regulations are frequently amended, the Company is unable to predict the future cost or impact of compliance. However, the Company does not expect that any of these laws and regulations will affect its operations materially differently than they would affect other companies with similar operations, size and financial strength.
Title to Properties
The leasehold properties we own are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with the use of these properties.
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Prior to drilling of an oil and natural gas well, it is normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our operators’ failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest. We believe the title to our properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry subject to such exceptions that, in the opinion of counsel employed in the various areas in which we have activities, are not so material as to detract substantially from the use of such properties.
Substantially all of our properties are currently mortgaged under a deed of trust to secure funding through a credit facility.
Insurance
Our operations are subject to all the risks inherent in the exploration for and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage.
Executive Officers
The following table sets forth certain information concerning the executive officers of the Company as of March 31, 2023.
| Name | Age | Position | ||
| Nicholas C. Taylor | 85 | Chairman and Chief Executive Officer | ||
| Tamala L. McComic | 54 | President, Chief Financial Officer, Treasurer, and Assistant Secretary | ||
| Donna Gail Yanko | 78 | Vice President | ||
| Stacy D. Hardin | 58 | Secretary and Assistant Treasurer |
Set forth below is a description of the principal occupations during at least the past five years of each executive officer of the Company.
Nicholas C. Taylor was elected Chairman of the Board and Chief Executive Officer of the Company in September 2011 and continues to serve in such capacity on a part time basis, as required. He served as Chief Executive Officer, President and Director of the Company from 1983 to 2011. From July 1993 to the present, Mr. Taylor has been involved in the independent practice of law and other business activities. In November 2005 he was appointed by the Speaker of the House to the Texas Ethics Commission and served until February 2010.
Tamala L. McComic, a Certified Public Accountant and Chartered Global Management Accountant, became Controller for the Company in July 2001 and was elected President and Chief Financial Officer in September 2011. She served the Company as Executive Vice President and Chief Financial Officer from 2009 to 2011 and Vice President and Chief Financial Officer from 2003 to 2009. Prior thereto, Ms. McComic served as Treasurer and Assistant Secretary of the Company.
Donna Gail Yanko was appointed to the position of Vice President of the Company in 1990. She also served as Corporate Secretary from 1992 to 2021 and from 1986 to 1992 was Assistant Secretary. From 1986 to 2015, on a part-time basis, she assisted the Chairman of the Board of the Company in his personal business activities. Ms. Yanko also served as a director of the Company from 1990 to 2008.
Stacy D. Hardin joined the Company in 2006 and was elected Corporate Secretary of the Company in September 2021. She has also served the Company as Assistant Treasurer of the Company since 2010 and from 2006 to 2021 was Assistant Secretary. Prior thereto, Ms. Hardin served as Assistant Controller.
Employees
As of March 31, 2023, we had three full-time and three part-time employees. We believe that relations with these employees are generally satisfactory. From time to time, we utilize the services of independent geological, land and engineering consultants on a limited basis and expect to continue to do so in the future.
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Office Facilities
Our principal offices are located at 415 W. Wall, Suite 475, Midland, Texas 79701 and our telephone number is (432) 682-1119. We believe our facilities are adequate for our current operations and future needs.
Access to Company Reports
Mexco Energy Corporation files annual, quarterly and current reports, proxy statements and other information with the SEC. The SEC maintains an internet website (www.sec.gov) that contains annual, quarterly and current reports, proxy statements and other information that issuers, including Mexco, file electronically with the SEC.
We also maintain an internet website at www.mexcoenergy.com. In the Investor Relations section, our website contains our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports and amendments to those reports as soon as reasonably practicable after such material is electronically filed with the SEC. Information on our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. Additionally, our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and Nominating Committee are posted on our website. Any of these corporate documents as well as any of the SEC filed reports are available in print free of charge to any stockholder who requests them. Requests should be directed to our corporate Secretary by mail to P.O. Box 10502, Midland, Texas 79702 or by email to mexco@sbcglobal.net.
ITEM 1A. RISK FACTORS
There are many factors that affect our business and results of operations, some of which are beyond our control. The following is a description of some of the important factors that could have a material adverse effect on our business, financial position, liquidity and results of operations. Some of the following risks relate principally to the industry in which we operate and to our business. Other risks relate principally to the securities markets and ownership of our common stock.
RISKS RELATED TO OUR BUSINESS AND INDUSTRY
Volatility of oil and gas prices significantly affects our results and profitability.
Prices for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations include the level of global demand for petroleum products; foreign supply and pricing of oil and gas; the actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls; nature and extent of governmental regulation and taxation, including environmental regulations; level of domestic and international exploration, drilling and production activity; the cost of exploring for, producing and delivering oil and gas; speculative trading in crude oil and natural gas derivative contracts; availability, proximity and capacity of oil and gas pipelines and other transportation facilities; weather conditions; the price and availability of alternative fuels; technological advances affecting energy consumption; national and international pandemics; and, overall political and economic conditions in oil producing countries.
Increases and decreases in prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks may be subject to redetermination based on changes in prices. In addition, we may have ceiling test writedowns when prices decline. Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance.
Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our exploration and development activities.
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Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower prices or lack of storage may have an adverse affect on our financial condition due to reduction of our revenues, operating income and cash flows; curtailment or shut-in of our production due to lack of transportation or storage capacity; cause certain properties in our portfolio to become economically unviable; and, limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations.
Our results of operations may be negatively impacted by current global events.
The economies in the United States and certain countries in Europe and Asia have been growing, with resulting improvements in industrial demand and consumer confidence. However, other economies, such as those of certain South American nations, continue to face economic struggles or slowing economic growth. If these conditions worsen, combined with a decline in economic growth in other parts of the world, there could be a significant adverse effect on global financial markets and commodity prices. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. Global or national health concerns may adversely affect the Company by (i) reducing demand for its oil, NGLs and gas because of reduced global or national economic activity, (ii) impairing its supply chain (for example, by limiting manufacturing of materials used in operations) and (iii) affecting the health of its workforce, rendering employees unable to work or travel. If the economic climate in the United States or abroad were to deteriorate, due to inflation, rising interest rates or otherwise, demand for petroleum products could diminish or stagnate, which could depress the prices at which the Company could sell its oil, NGLs and gas, affect the ability of the Company’s vendors, suppliers and customers to continue operations and ultimately decrease the Company’s cash flows and profitability. In addition, reduced worldwide demand for debt and equity securities issued by oil and gas companies may make it more difficult for the Company to raise capital to fund its operations or refinance its debt obligations.
Changes in environmental laws could increase our operators’ costs and adversely impact our business, financial condition and cash flows.
President Biden has indicated that he is supportive of, and has issued executive orders promoting various programs and initiatives designed to, among other things, curtail climate change, control the release of methane from new and existing oil and natural gas operations, and decarbonize electric generation and the transportation sector. In recent years the U.S. Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. For example, the Inflation Reduction Act of 2022 (the “IRA”), which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities, was signed into law in August 2022. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.
Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates elected to public office. President Biden has issued several executive orders focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas.
Lower oil and gas prices and other factors may cause us to record ceiling test writedowns.
Lower oil and gas prices increase the risk of ceiling limitation write-downs. We use the full cost method to account for oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties including the cost of abandoned properties, dry holes, geophysical costs and annual lease rentals. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded. Depletion of evaluated oil and natural gas properties is computed in the units of production method, whereby capitalized costs are amortized over total proved reserves. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10% plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess against earnings. This is called a “ceiling test writedown.” We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net reserves. Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test writedown does not impact cash flow from operating activities, but does reduce stockholders’ equity and earnings. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low. We incurred impairment charges during fiscal 2016 and may incur additional impairment charges in the future, particularly if commodity prices decline, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. There were no ceiling test impairments on our oil and gas properties during fiscal 2023 and 2022.
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We must replace reserves we produce.
Our future success depends upon our ability to find, develop or acquire additional, economically recoverable oil and gas reserves. Our proved reserves will generally decline as reserves are depleted, except to the extent that we can find, develop or acquire replacement reserves. One offset to the obvious benefits afforded by higher product prices especially for small to mid-cap companies in this industry, is that quality domestic oil and gas reserves are hard to find.
Approximately 26% and 37% of our total estimated net proved reserves at March 31, 2023 and 2022, respectively, were undeveloped, and those reserves may not ultimately be developed.
Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserve data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. Delays in the development of our reserves, increases in costs to develop such reserves, or decreases in commodity prices will reduce the future net revenues or our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, if we or the outside operators of our properties choose not to spend the capital to develop these reserves, or if we are not able to successfully develop these reserves, we will be required to write-off these reserves. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our common stock.
Information concerning our reserves and future net revenues estimates is inherently uncertain.
Estimates of oil and gas reserves, by necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, such as future production, oil and gas prices, operating costs, development costs and remedial costs, all of which may vary considerably from actual results. As a result, estimates of the economically recoverable quantities of oil and gas and of future net cash flows expected therefrom may vary substantially. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on a twelve month un-weighted first-day-of-the-month average oil and gas prices for the twelve months prior to the date of the report. Actual future prices and costs may be materially higher or lower.
An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations.
Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for our oil and gas are typically lower than the relevant benchmark prices, such as The New York Mercantile Exchange (“NYMEX”). The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. During fiscal 2023, differentials averaged $4.57 per Bbl of oil and ($0.28) per Mcf of gas. Increases in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce our revenues and our cash flow from operations.
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Drilling and operating activities are high risk activities that subject us to a variety of factors that we cannot control.
These factors include availability of workover and drilling rigs, well blowouts, cratering, explosions, fires, formations with abnormal pressures, pollution, releases of toxic gases and other environmental hazards and risks. Any of these operating hazards could result in substantial losses to us. In addition, we incur the risk that no commercially productive reservoirs will be encountered, and there is no assurance that we will recover all or any portion of our investment in wells drilled or re-entered.
We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.
We must make capital expenditures to develop our existing reserves and to acquire new reserves. Historically, we have used our cash flow from operations and borrowings under our credit facility to fund our capital expenditures, however, lower oil and gas prices may prevent these options. Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities.
The borrowing base under our credit facility will be determined from time to time by the lender. Reductions in estimates of oil and gas reserves could result in a reduction in the borrowing base, which would reduce the amount of financial resources available under the credit facility to meet our capital requirements. Such a reduction could be the result of lower commodity prices and/or production, inability to drill or unfavorable drilling results, changes in oil and gas reserve engineering, the lender’s inability to agree to an adequate borrowing base or adverse changes in the lender’s practices regarding estimation of reserves. If cash flow from operations or our borrowing base decrease for any reason, our ability to undertake exploration and development activities could be adversely affected. As a result, our ability to replace production may be limited.
Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management and outside operators have specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations.
Our business depends on oil and natural gas transportation facilities which are owned by others.
The marketability of our production depends in part on the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could all affect our ability to produce and market our oil and gas.
We have limited control over activities on properties we do not operate, which could reduce our production and revenues.
All of our business activities are conducted through joint operating or other agreements under which we own working and royalty interests in natural gas and oil properties in which we do not operate. As a result, we have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. The failure of an operator of our wells to adequately perform operations could reduce our revenues and production.
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Acquiring reserves in the oil and gas industry is highly competitive.
Competition for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed at a competitive disadvantage. Our ability to acquire and develop additional properties in the future will depend upon our ability to select and acquire suitable producing properties and prospects for future development activities.
We may not be insured against all of the operating hazards to which our business is exposed.
Our operations are subject to all the risks inherent in the exploration for, and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage.
Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may be eliminated as a result of proposed legislation.
Legislation previously has been proposed that would, if enacted into law, make significant changes to U. S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to crude oil and natural gas exploration and production companies. These changes include, but are not limited to: (1) the repeal of the percentage depletion allowance for crude oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain U.S. domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this type of legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to crude oil and natural gas exploration and development, and any such change could have an adverse effect on the value of an investment in our Common Stock as well as our financial position, results of operations and cash flows.
Our reliance on information technology, including those hosted by third parties, exposes us to cyber security risks that could affect our business, financial condition or reputation.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities, including digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate energy assets might be specific targets of cyber security threats. Our and our operators’ technologies, systems, networks, and those of vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business activities. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.
The loss of our chief executive officer or president could adversely impact our ability to execute our business strategy.
We depend, and will continue to depend in the foreseeable future, upon the continued services of our Chief Executive Officer, Nicholas C. Taylor and our President and Chief Financial Officer, Tamala L. McComic, who have extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties and developing and executing acquisitions and financing. As of March 31, 2023, we do not have key-man insurance on the lives of Mr. Taylor and Ms. McComic. The unexpected loss of the services of one or more of these individuals could, therefore, significantly and adversely affect our operations.
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We may be affected by one substantial shareholder.
Nicholas C. Taylor beneficially owns approximately 44% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations. The retirement, incapacity or death of Mr. Taylor, or any change in the power to vote shares beneficially owned by Mr. Taylor, could result in negative market or industry perception and could have an adverse effect on our business.
RISKS RELATED TO OUR COMMON STOCK
We may issue additional shares of common stock in the future, which could cause dilution to all shareholders.
We may seek to raise additional equity capital in the future. Any issuance of additional shares of our common stock will dilute the percentage ownership interest of all shareholders and may dilute the book value per share of our common stock.
Control by our executive officers and directors may limit your ability to influence the outcome of matters requiring stockholder approval and could discourage our potential acquisition by third parties.
As of March 31, 2023, our executive officers and directors beneficially owned approximately 47% of our common stock. These stockholders, if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions.
The price of our common stock has been volatile and could continue to fluctuate substantially.
Mexco common stock is traded on the New York Stock Exchange’s NYSE American. The market price of our common stock has and could continue to experience volatility due to reasons unrelated to our operating performance. These reasons include: supply and demand for oil and natural gas; political conditions in oil and natural gas producing regions; demand for our common stock and limited trading volume; investor perception of our industry; fluctuations in commodity prices; variations in our results of operations; legislative or regulatory changes; general trends in the oil and natural gas industry; market conditions and analysts’ estimates; and, other events in the oil and gas industry.
Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. As of March 31, 2023, we had interests in approximately 6,400 gross (18.5 net) producing oil and gas wells and owned leasehold mineral, royalty and other interests in approximately 544,000 gross (2,768 net) acres.
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Oil and Natural Gas Reserves
In accordance with current SEC rules, the average prices used in computing reserves at March 31, 2023 were $92.02 per bbl of oil compared to $74.52 in 2022, an increase of 23%, and $5.68 per mcf of natural gas compared to $4.60 in 2022, an increase of 23%, such prices are based on the 12-month unweighted arithmetic average market prices for sales of oil and natural gas on the first calendar day of each month during fiscal 2023. The benchmark price of $87.45 per bbl of oil at March 31, 2023 versus $71.72 at March 31, 2022, was adjusted by lease for gravity, transportation fees and market differentials and did not give effect to derivative transactions. The benchmark price of $5.96 per mcf of natural gas at March 31, 2023 versus $4.09 at March 31, 2022, was adjusted by lease for BTU content, transportation fees and market differentials.
For information concerning our costs incurred for oil and gas operations, net revenues from oil and gas production, estimated future net revenues attributable to our oil and gas reserves, present value of future net revenues discounted at 10% and changes therein, see Notes to the Company’s consolidated financial statements.
Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.
The engineering report with respect to Mexco’s estimates of proved oil and gas reserves as of March 31, 2023 and 2022 is based on evaluations prepared by Russell K. Hall and Associates, Inc. Environmental Engineering Consultants, based in Midland, Texas (“Hall and Associates”), a summary of which is filed as Exhibit 99.1 to this annual report.
Management maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations provided by the SEC. As stated above, Mexco retained Hall and Associates to prepare estimates of our oil and gas reserves. Management works closely with this firm, and is responsible for providing accurate operating and technical data to it. Our Chief Financial Officer who has over 25 years experience in the oil and gas industry reviews the final reserves estimate and consults with a degreed geological consultant with extensive geological experience and if necessary, discusses the process used and findings with Alan Neal, the technical person at Hall and Associates responsible for evaluating the proved reserves covered by this report. Mr. Neal is a member of the Society of Petroleum Engineers and has over 35 years of experience in the oil and gas industry. Our Chairman and Chief Executive Officer who has over 45 years of experience in the oil and gas industry also reviews the final reserves estimate.
Numerous uncertainties exist in estimating quantities of proved reserves. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn may adversely affect our cash flow, results of operations and the availability of capital resources.
Per the current SEC rules, the prices used to calculate our proved reserves and the present value of proved reserves set forth herein are made using the 12-month unweighted arithmetic average of the first-day-of-the-month price. All prices are held constant throughout the life of the properties. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value. Except to the extent that we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.
Our estimated proved oil and gas reserves and present value of estimated future net revenues from proved oil and gas reserves in the periods ended March 31 are summarized below.
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PROVED RESERVES
| March 31, | ||||||||
| 2023 | 2022 | |||||||
| Oil (Bbls): | ||||||||
| Proved developed – Producing | 451,000 | 391,060 | ||||||
| Proved developed – Non-producing | 35,770 | 37,620 | ||||||
| Proved undeveloped | 240,060 | 380,550 | ||||||
| Total | 726,830 | 809,230 | ||||||
| Natural gas (Mcf): | ||||||||
| Proved developed – Producing | 3,826,370 | 3,454,310 | ||||||
| Proved developed – Non-producing | 145,000 | 129,160 | ||||||
| Proved undeveloped | 978,010 | 1,258,220 | ||||||
| Total | 4,949,380 | 4,841,690 | ||||||
| Total net proved reserves (BOE) (1) | 1,551,725 | 1,616,180 | ||||||
| PV-10 Value (2) | $ | 39,473,000 | $ | 30,777,000 | ||||
| Present value of future income tax discounted at 10% | (6,658,000 | ) | (4,857,000 | ) | ||||
| Standardized measure of discounted future net cash flows (3) | $ | 32,815,000 | $ | 25,920,000 | ||||
| Prices used in Calculating Reserves: (4) | ||||||||
| Natural gas (per Mcf) | $ | 5.68 | $ | 4.60 | ||||
| Oil (per Bbl) | $ | 92.02 | $ | 74.52 | ||||
| (1) | These reserve estimates do not include the Company’s interest in two LLCs referred to in Item 1. Business – Company Profile on page 4 hereto. The first LLC has returned $226,725 and 76% of the total investment since inception in fiscal 2020. | |
| (2) | The PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10% per annum, which is the most directly comparable GAAP financial measure. PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. Our reconciliation of this non-GAAP financial measure is shown in the table as the PV-10, less future income taxes, discounted at 10% per annum, resulting in the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%. | |
| (3) | In accordance with SEC requirement, the standardized measure of discounted future net cash flows was computed by applying 12-month first day of the month average prices for oil and gas during the fiscal year to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. | |
| (4) | These prices reflect adjustment by lease for quality, transportation fees and market differentials. |
During fiscal 2023, we added proved reserves of 101 thousand BOE (“MBOE”) through extensions and discoveries, added 52 MBOE through acquisitions, subtracted 54 MBOE for downward revisions of previous estimates. Such downward revisions are primarily the result of reserves written off due to the five-year limitation and the change in the timing of new development. They are primarily royalty interests on leases in Loving, Pecos and Ward Counties, Texas which are held by production and still in place to be developed in the future.
During the fiscal year ending March 31, 2023, we had a working or royalty interest in the development of 59 wells converting reserves of approximately 186,000 BOE from proved undeveloped to proved developed – producing with capital cost of approximately $3,612,000.
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Oil and gas prices significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows. The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 932, “Extractive Activities – Oil and Gas”, may not necessarily be the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
We have not filed any other oil or gas reserve estimates or included any such estimates in reports to other federal or foreign governmental authority or agency during the year ended March 31, 2023, and no major discovery is believed to have caused a significant change in our estimates of proved reserves since that date.
Drilling Activities
The following table sets forth our drilling activity in wells in which we own a working interest for the years ended March 31:
| Year Ended March 31, | ||||||||||||||||
| 2023 | 2022 | |||||||||||||||
| Gross | Net | Gross | Net | |||||||||||||
| Exploratory Wells | ||||||||||||||||
| Beginning wells in progress | - | - | - | - | ||||||||||||
| Wells spud | - | - | - | - | ||||||||||||
| Successful wells | - | - | - | - | ||||||||||||
| Ending wells in progress | - | - | - | - | ||||||||||||
| Development Wells | ||||||||||||||||
| Beginning wells in progress | 11 | .04 | 12 | .06 | ||||||||||||
| Wells spud | 54 | .36 | 44 | .13 | ||||||||||||
| Successful wells | (44 | ) | (.35 | ) | (45 | ) | (.15 | ) | ||||||||
| Ending wells in progress | 21 | .05 | 11 | .04 | ||||||||||||
The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.
In addition to the working interests mentioned above, other operators drilled 85 gross wells (.04 net wells) on company-owned minerals and royalties at no expense to the Company. We expect the production of our mineral interests will increase as operators continue to drill, complete and develop our acreage. We expect to capitalize on this development, which requires no capital expenditure funding from us, and believe the anticipated aggregate royalty receipts will enable us to grow our cash flows. A number of the horizontal wells in which the Company participates involve longer lateral which are more efficient and have greater estimated ultimate recovery.
Productive Wells and Acreage
Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. Wells that are completed in more than one producing zone are counted as one well. As of March 31, 2023, we held an interest in approximately 6,400 gross (18.5 net) productive wells, including approximately 5,200 wells in which we held an overriding or royalty interest and 1,100 wells in which we held a working interest.
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A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres. The following table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2023:
| Acreage | ||||||||
| Gross | Net | |||||||
| Texas | 348,600 | 1,586 | ||||||
| Oklahoma | 70,900 | 884 | ||||||
| Louisiana | 35,300 | 25 | ||||||
| New Mexico | 30,600 | 185 | ||||||
| North Dakota | 22,600 | 29 | ||||||
| Ohio | 14,500 | 1 | ||||||
| Kansas | 8,500 | 41 | ||||||
| Montana | 5,000 | 1 | ||||||
| Wyoming | 3,800 | 5 | ||||||
| Arkansas | 1,600 | 5 | ||||||
| Colorado | 1,100 | 1 | ||||||
| Alabama | 1,000 | 2 | ||||||
| Mississippi | 700 | 2 | ||||||
| Virginia | 100 | 1 | ||||||
| Total | 544,300 | 2,768 | ||||||
Net Production, Unit Prices and Costs
The following table summarizes our net oil and natural gas production, the average sales price per barrel (“bbl”) of oil and per thousand cubic feet (“mcf”) of natural gas produced and the average production (lifting) cost per unit of production for the years ended March 31:
| Years Ended March 31, | ||||||||
| 2023 | 2022 | |||||||
| Oil (a): | ||||||||
| Production (Bbls) | 73,968 | 61,689 | ||||||
| Revenue | $ | 6,522,163 | $ | 4,685,094 | ||||
| Average Bbls per day (d) | 203 | 169 | ||||||
| Average sales price per Bbl | $ | 88.18 | $ | 75.95 | ||||
| Gas (b): | ||||||||
| Production (Mcf) | 534,363 | 393,841 | ||||||
| Revenue | $ | 2,858,460 | $ | 1,840,170 | ||||
| Average Mcf per day (d) | 1,464 | 1,079 | ||||||
| Average sales price per Mcf | $ | 5.35 | $ | 4.67 | ||||
| Total BOE (c) | 163,029 | 127,329 | ||||||
| Production costs: | ||||||||
| Production expenses: | $ | 1,039,893 | $ | 778,308 | ||||
| Production expenses per BOE | $ | 6.38 | $ | 6.11 | ||||
| Production expenses per sales dollar | $ | 0.11 | $ | 0.12 | ||||
| Production and ad valorem taxes: | $ | 679,826 | $ | 502,804 | ||||
| Production and ad valorem taxes per BOE | $ | 4.17 | $ | 3.95 | ||||
| Production and ad valorem taxes per sales dollar | $ | 0.07 | $ | 0.08 | ||||
| Total oil and gas revenue | $ | 9,380,623 | $ | 6,525,264 | ||||
| (a) | Includes condensate. | |
| (b) | Includes natural gas products. | |
| (c) | Natural gas production is converted to oil production using a ratio of six Mcf to one Bbl of oil. | |
| (d) | Calculated on a 365 day year. |
ITEM 3. LEGAL PROCEEDINGS
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. We are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under various environmental protection statutes or other regulations to which we are subject.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
In September 2003, our common stock began trading on the NYSE American, formerly the American Stock Exchange and more recently the NYSE MKT, under the symbol “MXC”. Prior to September 2003, the Company’s common stock was traded on the over-the-counter bulletin board market under the symbol “MEXC”. The registrar and transfer agent is Issuer Direct Corporation, 500 Perimeter Park Drive, Suite D, Morrisville, North Carolina, 27560 (Tel: 877-481-4014). The following table sets forth certain information as to the high and low sales price quoted for Mexco’s common stock on the NYSE American.
| High | Low | |||||||||
| 2023: | April - June 2022 | $ | 24.18 | $ | 13.79 | |||||
| July - September 2022 | 20.84 | 14.43 | ||||||||
| October - December 2022 | 18.25 | 12.40 | ||||||||
| January - March 2023 | 15.39 | 10.50 | ||||||||
| 2022: | April - June 2021 | $ | 10.60 | $ | 6.88 | |||||
| July - September 2021 | 11.80 | 7.80 | ||||||||
| October - December 2021 | 18.00 | 8.35 | ||||||||
| January - March 2022 | 43.00 | 9.00 | ||||||||
On March 31, 2023, the closing sales price of our common stock on the NYSE American was $11.38 per share.
Stockholders
As of March 31, 2023, we had 2,221,416 shares issued and 849 shareholders of record which does not include shareholders for whom shares are held in a “nominee” or “street” name. Of these issued shares, 85,416 are held in the treasury.
Dividends
As of March 31, 2023, the Company had never paid a cash dividend to the Company’s shareholders. Payment of dividends are at the discretion of our Board of Directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our current bank loan prohibits us from paying cash dividends on our common stock without written permission.
Subsequently, on April 10, 2023, the Company announced that its Board of Directors declared a special dividend of $0.10 per common share to its shareholders of record at the close of business on May 1, 2023. The special dividend was paid on May 15, 2023. The Company obtained written permission from WTNB prior to declaring the special dividend.
The Company can provide no assurance that dividends will be authorized or declared in the future or as to the amount or type of any future dividends. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.
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Securities Authorized for Issuance Under Compensation Plans
The following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2023, which has been approved by our stockholders.
| Number of Shares Authorized for Issuance under Plan | Number of Shares to be Issued upon Exercise of Outstanding Options | Weighted Average Exercise Price of Outstanding Options | Number of Shares Remaining Available for Future Issuance under Plan | |||||||||||||
| 2009 Plan | 200,000 | 45,250 | $ | 5.27 | - | |||||||||||
| 2019 Plan | 200,000 | 94,000 | 9.85 | 98,000 | ||||||||||||
| Total | 400,000 | 139,250 | $ | 8.36 | 98,000 | |||||||||||
Issuer Repurchases
In September 2022, the board of directors authorized the use of up to $250,000 to repurchase shares of our common stock for the treasury account. This program does not have an expiration date and may be modified, suspended or terminated at any time by the board of directors. Under the repurchase program, shares of common stock may be purchased from time to time through open market purchases or other transactions. The amount and timing of repurchases will be subject to the availability of stock, prevailing market conditions, the trading price of the stock, our financial performance and other conditions. Repurchases may also be made from time-to-time in connection with the settlement of our share-based compensation awards. Repurchases will be funded from cash flow from operations.
The following table provides information related to repurchases of our common stock for the treasury account during the year ended March 31, 2023:
| Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Program | Approximate Dollar Value of Shares that May Yet be Purchased Under the Program | |||||||||||||
| November 1-30, 2022 | 3,716 | $ | 14.51 | 3,716 | $ | 196,072 | ||||||||||
| December 1-31, 2022 | 8,700 | $ | 13.14 | 8,700 | $ | 81,740 | ||||||||||
| January 1-31, 2023 | 1,300 | $ | 12.58 | 1,300 | $ | 65,381 | ||||||||||
| February 1-28, 2023 | 1,727 | $ | 12.75 | 1,727 | $ | 43,359 | ||||||||||
| March 1-31, 2023 | 2,973 | $ | 12.73 | 2,973 | $ | 5,506 | ||||||||||
During the year ended March 31, 2023, the Company repurchased 18,416 shares for the treasury account at an aggregate cost of $244,494, an average price of $13.28 per share. There were no shares of our common stock repurchased for the treasury account during the fiscal year ended March 31, 2022.
Subsequently, in April 2023, the Company’s Board of Directors authorized the use of up to $1,000,000 to repurchase shares of the Company’s common stock, par value, $0.50, for the treasury account. This authorization replaced the previously authorized $250,000 common stock repurchase program which had $5,506 remaining at the time it was replaced.
On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases after December 31, 2022. The IRA 2022 does provide for certain exceptions for repurchases of stock including an exception as long as the aggregate value of the repurchases for the tax year does not exceed $1,000,000.
ITEM 6. RESERVED
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K.
Liquidity and Capital Resources and Commitments
Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our primary financial resource is our base of oil and gas reserves. We have pledged our producing oil and gas properties to secure our credit facility. We do not have any delivery commitments to provide a fixed and determinable quantity of our oil and gas under any existing contract or agreement.
Our long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low-cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interests and non-operated properties in areas with significant development potential.
Cash Flows
Changes in the net funds provided by or (used in) each of our operating, investing and financing activities are set forth in the table below:
| For the Years Ended March 31, | ||||||||||||
| 2023 | 2022 | Change | ||||||||||
| Net cash provided by operating activities | $ | 6,515,895 | $ | 3,744,407 | $ | 2,771,488 | ||||||
| Net cash used in investing activities | $ | (5,441,075 | ) | $ | (1,710,024 | ) | $ | 3,731,051 | ||||
| Net cash used in financing activities | $ | (209,815 | ) | $ | (721,430 | ) | $ | (511,615 | ) | |||
Cash Flow Provided by Operating Activities. Cash flow from operating activities is primarily derived from the production of our crude oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances. Cash flow provided by our operating activities for the year ended March 31, 2023 was $6,515,895 in comparison to $3,744,407 for the year ended March 31, 2022. This increase of $2,771,488 in our cash flow operating activities consisted of an increase in our non-cash expenses of $565,838; a decrease in our accounts receivable of $594,673; a decrease of $128,615 in our accounts payable and accrued expenses; and, an increase in our net income of $1,807,636. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.
Our expenditures in operating activities consist primarily of production expenses and engineering services. Our expenses also consist of employee compensation, accounting, insurance and other general and administrative expenses that we have incurred in order to address normal and necessary business activities of a public company in the crude oil and natural gas production industry.
Cash Flow Used in Investing Activities. Cash flow from investing activities is derived from changes in oil and gas property balances. For the year ended March 31, 2023, we had net cash of $5,014,357 used for additions to oil and gas properties and a $425,000 investment in two limited liability companies compared to $1,635,024 and $75,000, respectively, for the year ended March 31, 2022.
Cash Flow Used in Financing Activities. Cash flow from financing activities is derived from our changes in long-term debt and in equity account balances. Net cash flow used in our financing activities was $209,815 for the year ended March 31, 2023 compared to net cash flow used in our financing activities of $721,430 for the year ended March 31, 2022. During the year ended March 31, 2023, we received advances and made payments of $675,000 on our credit facility, received proceeds of $16,700 from the exercise of director stock options, received payment of $30,179 form a director for profits on purchase of stock within the six-month window of a previous stock sale, expended $244,494 for the purchase of 18,416 shares of our stock for the treasury and, expended $12,200 for the renewal of our credit facility. During the year ended March 31, 2022, we received advances of $275,000 and made payments of $1,455,000 on our credit facility and received proceeds of $458,570 for the exercise of employee and director stock options.
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Accordingly, net cash increased $865,005, leaving cash and cash equivalents on hand of $2,235,771 as of March 31, 2023.
We had working capital of $3,475,776 as of March 31, 2023 compared to working capital of $2,469,776 as of March 31, 2022, an increase of $1,006,000 for the reasons set forth below.
Oil and Natural Gas Property Development.
New Participations in Fiscal 2023. The Company participated in the drilling and completion of 50 horizontal wells at a cost of approximately $4,200,000, of which $3,750,000 was expended during the fiscal year ending March 31, 2023. Eighteen of these wells have not been completed. Thirty-nine of these horizontal wells are in the Delaware Basin located in the western portion of the Permian Basin in Lea and Eddy Counties, New Mexico and twelve are in the Midland Basin located in the eastern portion of the Permian Basin in Reagan County, Texas.
In addition to the above working interests, there were 85 gross wells (.04 net wells) drilled by other operators on Mexco’s royalty interests and 50 gross wells (.29 net wells) obtained through acquisitions.
In April 2022, Mexco expended approximately $176,000 to participate in the drilling of four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .52%. Subsequently, in May 2023, Mexco expended approximately $211,000 to complete these wells.
Mexco expended approximately $1,196,000 to participate in the drilling and completion of three horizontal wells in the Wolfcamp Sand formation of the Midland Basin located in the eastern portion of the Permian Basin in Reagan County, Texas. Mexco’s working interest in these wells is 3.2%. These wells were completed in October 2022 with initial average production rates of 507 barrels of oil, 2,147 barrels of water and 2,147,000 cubic feet of gas per day, or, 560 barrels of oil equivalent per day.
Mexco expended approximately $681,000 to participate in the drilling and completion of eight horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .52%. These wells were completed in February and March 2023 with initial average production rates of 1,011 barrels of oil, 4,581 barrels of water and 3,577,000 cubic feet of gas per day, or 1,607 barrels of oil equivalent per day.
Mexco expended approximately $607,000 to participate in the drilling and completion of a horizontal well in the Wolfcamp Sand formation of the Midland Basin in Reagan County, Texas. Mexco’s working interest in this well is 5.1%. This well was completed in October 2022 with initial average production rates of 295 barrels of oil, 1,313 barrels of water and 237,000 cubic feet of gas per day, or, 335 barrels of oil equivalent per day.
Mexco expended approximately $649,000 to participate in the drilling and completion of four horizontal wells in the Bone Spring formation of the Delaware Basin in Eddy County, New Mexico. Mexco’s working interest in these wells is 2.1%. These wells began producing in October 2022 with initial average production rates of 1,154 barrels of oil, 2,887 barrels of water and 2,966,000 cubic feet of gas per day, or, 1,648 barrels of oil equivalent per day.
Mexco expended approximately $84,000 to participate in the drilling and completion of two horizontal wells in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .22%. These wells began producing in January 2023 with initial average production rates of 1,367 barrels of oil, 3,900 barrels of water and 1,786,000 cubic feet of gas per day, or, 1,665 barrels of oil equivalent per day.
Mexco expended approximately $30,000 to participate in the drilling and completion of two horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .1%. These wells began producing in February 2023 with initial average production rates of 622 barrels of oil, 1,991 barrels of water and 262,000 cubic feet of gas per day, or, 666 barrels of oil equivalent per day.
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Mexco expended approximately $93,000 to participate in the drilling and completion of eight horizontal wells in the Spraberry trend of the Midland Basin in Reagan County, Texas. Mexco’s working interest in these wells is approximately .11%. These wells began producing in December 2022.
Mexco expended $16,000 to participate in the drilling and completion of three horizontal wells in the Bone Spring formation of the Delaware Basin in Eddy County, New Mexico. Mexco’s working interest in these wells is .05%. These wells were subsequently completed in May 2023 with initial average production rates of 437 barrels of oil, 983 barrels of water and 603,000 cubic feet of gas per day, or, 538 barrels of oil equivalent per day.
In February 2023, Mexco expended approximately $31,000 to participate in the drilling and completion of seven horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately .03%. These wells are currently being completed.
In January 2023, Mexco expended $180,000 to participate in the drilling of four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately .52%. These wells are currently awaiting completion operations.
In March 2023, Mexco expended approximately $60,000 to participate in the drilling of two horizontal wells in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately .285%. These wells began drilling in April 2023.
In October 2022, the Company made an approximately 2% equity investment commitment in a limited liability company amounting to $2,000,000 of which $400,000 has been funded to date. The limited liability company is capitalized at approximately $100 million to purchase mineral interests in the Utica and Marcellus areas in the state of Ohio.
Completion of Wells Drilled in Fiscal 2023. The Company expended approximately $329,000 for the completion costs of 8 horizontal wells located in Lea County, New Mexico that the Company participated in drilling during fiscal 2022. The first 4 of these wells began producing in May 2022 and the remaining 4 were completed in November 2022 with initial average production rates of 1,168 barrels of oil, 3,797 barrels of water and 2,621,000 cubic feet of gas per day, or, 1,605 barrels of oil equivalent per day.
Acquisitions in Fiscal 2023. The Company acquired various royalty (mineral) interests in 22 wells and several additional potential locations for development operated by Chesapeake Energy Corporation and located in the Eagleford area of Dimmit County, Texas for a purchase price of $939,000 which was effective April 1, 2022.
The Company also acquired, for a purchase price of $117,200, royalty interests covering 28 producing wells in 6 counties in the Haynesville trend area of Louisiana and 5 counties in Texas.
Subsequent Participations. In May 2023, Mexco expended approximately $133,000 to participate in the drilling of four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico.
Mexco expended approximately $68,000 to participate in the drilling of two horizontal wells in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico.
We are participating in other projects and are reviewing projects in which we may participate. The cost of such projects would be funded, to the extent possible, from existing cash balances and cash flow from operations. The remainder may be funded through borrowings on the credit facility and, if appropriate, sales of non-core properties.
Markets. Crude oil and natural gas prices generally remained volatile during the last year. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $62.72 per bbl in March 2023 to a high of $118.09 per bbl in June 2022. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.93 per MMBtu in March 2023 to a high of $9.85 per MMBtu in August 2022.
On March 31, 2023 the WTI posted price for crude oil was $71.65 per bbl and the Henry Hub spot price for natural gas was $2.10 per MMBtu. See Results of Operations below for realized prices.
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Results of Operations
Fiscal 2023 Compared to Fiscal 2022
We had net income of $4,662,702 for the year ended March 31, 2023 compared to $2,855,066 for the year ended March 31, 2022, a 63% increase as a result of an increase in operating revenues due to an increase in oil and natural gas prices and production partially offset by an increase in operating expenses that is further explained below.
Oil and natural gas sales. Revenue from oil and natural gas sales was $9,380,623 for the year ended March 31, 2023, a 44% increase from $6,525,264 for the year ended March 31, 2022. This resulted from an increase in oil and natural gas production volumes and an increase in oil and natural gas prices. The following table sets forth our oil and natural gas revenues, production quantities and average prices received during the fiscal years ended March 31:
| 2023 | 2022 | % Difference | ||||||||||
| Oil: | ||||||||||||
| Revenue | $ | 6,522,163 | $ | 4,685,094 | 39.2 | % | ||||||
| Volume (bbls) | 73,968 | 61,689 | 19.9 | % | ||||||||
| Average Price (per bbl) | $ | 88.18 | $ | 75.95 | 16.1 | % | ||||||
| Gas: | ||||||||||||
| Revenue | $ | 2,858,460 | $ | 1,840,170 | 55.3 | % | ||||||
| Volume (mcf) | 534,363 | 393,841 | 35.7 | % | ||||||||
| Average Price (per mcf) | $ | 5.35 | $ | 4.67 | 14.6 | % | ||||||
Production and exploration. Production costs were $1,719,719 in fiscal 2023, a 34% increase from $1,281,112 in fiscal 2022. This was primarily the result of an increase in production taxes and marketing charges as a result of the increase in oil and gas revenues.
Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $1,854,047 in fiscal 2023, a 38% increase from $1,345,435 in fiscal 2022. This was primarily due to an increase in oil and gas production and an increase in the full cost pool amortization and a decrease in the oil and gas reserves.
General and administrative expenses. General and administrative expenses were $1,120,691 for the year ended March 31, 2023, an 18% increase from $949,079 for the year ended March 31, 2022. This was primarily due to an increase in employee stock option compensation, salaries and contract services, legal and accounting fees.
Interest expense. Interest expense was $13,097 in fiscal 2023, a 51% decrease from $26,512 in fiscal 2022, due to a decrease in borrowings.
Income taxes. There was no federal income tax for fiscal 2023 or fiscal 2022. We are in a net deferred tax asset position and believe it is more likely than not that these deferred tax assets will not be realized. State income tax was $164,510 in fiscal 2023, a 61% increase from $102,356 in fiscal 2022, due to the increase in oil and natural gas sales. The effective tax rate for fiscal 2023 and fiscal 2022 was 3.4% and 3.5%, respectively.
Contractual Obligations
We have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes future payments we are obligated to make based on agreements in place as of March 31, 2023:
| Payments due in: | ||||||||||||||||
| Total | less than 1 year | 1 - 3 years | over 3 years | |||||||||||||
| Contractual obligations: | ||||||||||||||||
| Leases (1) | $ | 77,653 | $ | 58,240 | $ | 19,413 | $ | - | ||||||||
| (1) | The lease amount represents the monthly rent amount for our principal office space in Midland, Texas under a 38-month lease agreement effective May 15, 2018 and extended another 36 months to July 31, 2024. Of this total obligation for the remainder of the lease, our majority shareholder will pay $15,572 less than 1 year and $5,191 1-3 years for his portion of the shared office space. |
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Alternative Capital Resources
Although we have primarily used cash from operating activities, the sales of assets and funding from the credit facility as our primary capital resources, we have in the past, and could in the future, use alternative capital resources. These could include joint ventures, carried working interests and issuances of our common stock through a private placement or public offering.
Other Matters
Critical Accounting Policies and Estimates
In preparing financial statements, management makes informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, fair value and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.
Full Cost Method of Accounting for Crude Oil and Natural Gas Activities. SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred.
Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the sale would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of crude oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher DD&A rate on our crude oil and natural gas properties.
At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us more susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. Our crude oil and natural gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from the full cost method of accounting.
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Ceiling Test. Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce our stockholders’ equity and reported earnings.
The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period.
Estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgment of the persons preparing the estimate. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.
It should not be assumed that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, the cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production using the average price over the prior 12-month period.
The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost projects.
Use of Estimates. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining year end proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of our oil and natural gas reserves, which is used to compute DD&A and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.
Excluded Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the DD&A pool). Impairments transferred to the DD&A pool increase the DD&A rate.
Revenue Recognition - Revenue from Contracts with Customers. Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to three months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant.
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Asset Retirement Obligations. The estimated costs of plugging, restoration and removal of facilities are accrued. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated by the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in the full cost amortization base and amortize these costs as a component of our depletion expense.
Gas Balancing. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when our excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where Mexco has taken less than its ownership share of gas production (under produced).
Stock-based Compensation. We use the Binomial option pricing model to estimate the fair value of stock-based compensation expenses at grant date. This expense is recognized as compensation expense in our financial statements over the vesting period. We recognize the fair value of stock-based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period.
Accounts Receivable. Our accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectability of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on our previous loss history.
Income Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.
Other Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years.
Investments. The Company accounts for investments of less than 3% of any limited liability companies at cost. The Company has no control of the limited liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations.
Reclassifications. Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s presentation. These reclassifications had no effect on previously reported results of operations, retained earnings or net cash flows.
Leases. The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets.
Operating lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate, the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 3.75%. Significant judgement is required when determining the incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term.
| 28 |
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary source of market risk for us includes fluctuations in commodity prices and interest rates. All of our financial instruments are for purposes other than trading.
Credit Risk. Credit risk is the risk of loss as a result of nonperformance by other parties of their contractual obligations. Our primary credit risk is related to oil and gas production sold to various purchasers and the receivables are generally not collateralized. At March 31, 2023, our largest credit risk associated with any single purchaser was $634,672 or 46% of our total oil and gas receivables. We have not experienced any significant credit losses.
Energy Price Risk. Our most significant market risk is the pricing applicable to our crude oil and natural gas production. Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. Prices for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future.
Factors that can cause price fluctuations include the level of global demand for petroleum products, foreign and domestic supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall political and economic conditions in oil producing and consuming countries.
For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $62.72 per bbl in March 2023 to a high of $118.09 per bbl in June 2022. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.93 per MMBtu in March 2023 to a high of $9.85 per MMBtu in August 2022. On March 31, 2023 the WTI posted price for crude oil was $71.65 per bbl and the Henry Hub spot price for natural gas was $2.10 per MMBtu. See Results of Operations above for the Company’s realized prices during the fiscal year. Subsequently, on June 21, 2023, the WTI posted price for crude oil was $68.51 and the Henry Hub posted price for natural gas was $2.24.
Declines in oil and natural gas prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our acquisition, exploration and development activities. In addition, a noncash write-down of our oil and gas properties could be required under full cost accounting rules if prices declined significantly, even if it is only for a short period of time. See Critical Accounting Policies and Estimates — Ceiling Test under Item 7 of this report on Form 10-K. Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance.
Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. If the average oil price had increased or decreased by ten dollars per barrel for fiscal 2023, our pretax income would have changed by $739,680. If the average gas price had increased or decreased by one dollar per mcf for fiscal 2023, pretax income would have changed by $534,363.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears on pages F2 through F20 hereof and are incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
| 29 |
ITEM 9A. CONTROLS AND PROCEDURES
Management’s Annual Report on Internal Control over Financial Reporting. The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel, and a written Code of Conduct adopted by our Board of Directors, applicable to all directors, officers and employees of Mexco.
Our chief executive officer and chief financial officer assessed the effectiveness our internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 “Internal Control - Integrated Framework”. Based upon that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of March 31, 2023.
Evaluation of Disclosure Controls and Procedures. We maintain disclosure controls and procedures to ensure that the information we must disclose in our filings with the SEC is recorded, processed, summarized and reported on a timely basis. At the end of the period covered by this report, our principal executive officer and principal financial officer reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). Based on such evaluation, such officers concluded that, as of March 31, 2023, our disclosure controls and procedures were effective.
Changes in Internal Control over Financial Reporting. No changes in the Company’s internal control over financial reporting occurred during the year ended March 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTION
Not applicable
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
See “Mexco Energy Corporation Board of Directors”, “Named Executive Officers Who Are Not Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, “Corporate Governance and Code of Business Conduct” and “Meetings and Committees of the Board of Directors” in the Proxy Statement of Mexco Energy Corporation for our Annual Meeting of Stockholders to be held September 12, 2023 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2023, which is incorporated herein by reference.
The information required by this item with respect to executive officers of the Company is also set forth in Part I of this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation”, and is hereby incorporated herein by reference.
| 30 |
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item will be contained in the Proxy Statement under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Employee Incentive Stock Option Plans”, and is hereby incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item will be contained in the Proxy Statement under the captions “Certain Relationships and Related Transactions” and “Meetings and Committees of the Board of Directors”, and is hereby incorporated by reference herein.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item will be contained in the Proxy Statement under the caption “Audit Fees and Services”, and is hereby incorporated by reference herein.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Consolidated Financial Statements. For a list of the consolidated financial statements filed as part of this Form 10-K, see the “Index to Consolidated Financial Statements” set forth on F-1 of this report.
Financial Statement Schedules. All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto.
Exhibits. For a list of the exhibits required by this Item and accompanying this Form 10-K see the “Index to Exhibits” set forth on page F21 of this report.
ITEM 16. FORM 10-K SUMMARY
None
| 31 |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
MEXCO ENERGY CORPORATION
| By: | /s/ Nicholas C. Taylor | By: | /s/ Tamala L. McComic | |
| Chairman of the Board and Chief Executive Officer | President and Chief Financial Officer |
Dated: June 26, 2023
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 26, 2023, by the following persons on behalf of the Registrant and in the capacity indicated.
| /s/ Nicholas C. Taylor | ||
| Nicholas C. Taylor | ||
| Chief Executive Officer, Chairman of the Board of Directors | ||
| /s/ Tamala L. McComic | ||
| Tamala L. McComic | ||
| Chief Financial Officer, President, Treasurer and Assistant Secretary | ||
| /s/ Michael J. Banschbach | ||
| Michael J. Banschbach | ||
| Director | ||
| /s/ Kenneth L. Clayton | ||
| Kenneth L. Clayton | ||
| Director | ||
| /s/ Thomas R. Craddick | ||
| Thomas R. Craddick | ||
| Director | ||
| /s/ Thomas H. Decker | ||
| Thomas H. Decker | ||
| Director | ||
| /s/ Christopher M. Schroeder | ||
| Christopher M. Schroeder | ||
| Director | ||
| 32 |
Glossary of Abbreviations and Terms
The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.
Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate or natural gas liquids hydrocarbons.
BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BTU. British thermal unit.
Completion. The installation of permanent equipment for the production of oil or natural gas.
Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Credit Facility. A line of credit provided by a bank or group of banks, secured by oil and gas properties.
DD&A. Refers to depreciation, depletion and amortization of the Company’s property and equipment.
Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.
Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Extensions and discoveries. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. A layer of rock which has distinct characteristics that differs from nearby rock.
Gross acres or wells. Refers to the total acres or wells in which the Company owns any amount of working interest.
Lease. An instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove oil and natural gas from the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing.
Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.
| 33 |
MBOE. One thousand barrels of oil equivalent.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units of energy commonly used to measure heat value or energy content of natural gas.
Natural gas liquids (“NGLs”). Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.
Net acres or wells. Refers to gross acres or wells multiplied, in each case, by the percentage interest owned by the Company.
Net production. Oil and gas production that is owned by the Company, less royalties and production due others.
Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
Oil. Crude oil or condensate.
Operator. The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease.
Overriding royalty interest (“ORRI”). A royalty interest that is created out of the operating or working interest. Its term is coextensive with that of the operating interest from which it was created.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed operating and production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed nonproducing reserves (“PDNP”). Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.
Proved developed producing reserves (“PDP”). Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.
Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves.
Proved reserves. The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves (“PUD”). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
| 34 |
PV-10. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10%.
Recompletion. A process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Shut in. A well suspended from production or injection but not abandoned.
Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies.
Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10% annual discount rate. The information for this calculation is included in the note regarding disclosures about oil and gas reserve data contained in the Notes to Consolidated Financial Statements included in this Form 10-K.
Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
Wellbore. The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called well or borehole.
Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.
| 35 |
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| F-1 |
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Mexco Energy Corporation
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Mexco Energy Corporation (a Colorado corporation) and Subsidiaries (the Company) as of March 31, 2023 and 2022, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the two years in the period ended March 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of March 31, 2023 and 2022, and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to Mexco Energy Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Estimation of proved reserves impacting the recognition and valuation of depletion expense and impairment of oil and gas properties.
Critical Accounting Matter Description
As described in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.
| F-2 |
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
How the Critical Audit Matter Was Addressed in the Audit
We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others.
| ● | We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists. |
| ● | To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows: |
| - | Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year; |
| - | Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs; |
| - | Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations; |
| - | Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interests, historical pricing differentials, and operating costs to underlying support from the Company’s accounting records; |
| - | Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s or the operator’s intent to develop the proved undeveloped properties; |
| - | Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report. |
/s/
We have served as the Company’s auditor since 2017.
PCAOB
ID #
June 26, 2023
| F-3 |
Mexco
Energy Corporation and Subsidiaries
CONSOLIDATED BALANCE SHEETS
| March 31, | March 31, | |||||||
| 2023 | 2022 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | $ | ||||||
| Accounts receivable: | ||||||||
| Oil and natural gas sales | ||||||||
| Trade | ||||||||
| Prepaid drilling | ||||||||
| Prepaid costs and expenses | ||||||||
| Total current assets | ||||||||
| Property and equipment, at cost | ||||||||
| Oil and gas properties, using the full cost method | ||||||||
| Other | ||||||||
| Accumulated depreciation, depletion and amortization | ( | ) | ( | ) | ||||
| Property and equipment, net | ||||||||
| Investment – cost basis | ||||||||
| Operating lease, right-of-use asset | ||||||||
| Other noncurrent assets | ||||||||
| Total assets | $ | $ | ||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
| Current liabilities | ||||||||
| Accounts payable and accrued expenses | $ | $ | ||||||
| Operating lease liability, current | ||||||||
| Total current liabilities | ||||||||
| Long-term liabilities | ||||||||
| Long-term debt | ||||||||
| Operating lease liability, long-term | ||||||||
| Asset retirement obligations | ||||||||
| Total long-term liabilities | ||||||||
| Total liabilities | ||||||||
| Commitments and contingencies | ||||||||
| Stockholders’ equity | ||||||||
| Preferred stock - $ par value; shares authorized; outstanding | ||||||||
| Common stock - $ par value;
shares authorized; and shares issued; and, and shares outstanding as of March 31, 2023 and 2022 | ||||||||
| Additional paid-in capital | ||||||||
| Retained earnings | ||||||||
| Treasury stock, at cost ( and shares, respectively) | ( | ) | ( | ) | ||||
| Total stockholders’ equity | ||||||||
| Total liabilities and stockholders’ equity | $ | $ | ||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
| F-4 |
Mexco Energy Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
Years ended March 31,
| 2023 | 2022 | |||||||
| Operating revenues: | ||||||||
| Oil sales | $ | $ | ||||||
| Natural gas sales | ||||||||
| Other | ||||||||
| Total operating revenues | ||||||||
| Operating expenses: | ||||||||
| Production | ||||||||
| Accretion of asset retirement obligation | ||||||||
| Depreciation, depletion and amortization | ||||||||
| General and administrative | ||||||||
| Total operating expenses | ||||||||
| Operating income | ||||||||
| Other income (expenses): | ||||||||
| Interest income | ||||||||
| Interest expense | ( | ) | ( | ) | ||||
| Net other expense | ( | ) | ( | ) | ||||
| Income before provision for income taxes | ||||||||
| State income tax expense | ||||||||
| Net income | $ | $ | ||||||
| Income per common share: | ||||||||
| Basic: | $ | $ | ||||||
| Diluted: | $ | $ | ||||||
| Weighted average common shares outstanding: | ||||||||
| Basic: | ||||||||
| Diluted: | ||||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
| F-5 |
Mexco
Energy Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
Years ended March 31, 2023 and 2022
| Common Stock Par Value | Additional Paid-In Capital | Retained Earnings | Treasury Stock | Total Stockholders’ Equity | ||||||||||||||||
| Balance at April 1, 2021 | $ | $ | $ | $ | ( | ) | $ | |||||||||||||
| Net income | ||||||||||||||||||||
| Issuance of stock through options exercised | ||||||||||||||||||||
| Stock based compensation | ||||||||||||||||||||
| Balance at March 31, 2022 | $ | $ | $ | $ | ( | ) | $ | |||||||||||||
| Net income | ||||||||||||||||||||
| Issuance of stock through options exercised | ||||||||||||||||||||
| Profit from purchase of stock by insider | ||||||||||||||||||||
| Purchase of stock | ||||||||||||||||||||
| Stock based compensation | ||||||||||||||||||||
| Balance at March 31, 2023 | $ | $ | $ | $ | ( | ) | $ | |||||||||||||
| SHARE ACTIVITY | ||||||||
| 2023 | 2022 | |||||||
| Common stock shares, issued: | ||||||||
| At beginning of year | ||||||||
| Issued | ||||||||
| At end of year | ||||||||
| Common stock shares, held in treasury: | ||||||||
| At beginning of year | ( | ) | ( | ) | ||||
| Acquisitions | ( | ) | ||||||
| At end of year | ( | ) | ( | ) | ||||
| Common stock shares, outstanding | ||||||||
| At end of year | ||||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
| F-6 |
Mexco
Energy Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended March 31,
| 2023 | 2022 | |||||||
| Cash flows from operating activities: | ||||||||
| Net income | $ | $ | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
| Stock-based compensation | ||||||||
| Depreciation, depletion and amortization | ||||||||
| Accretion of asset retirement obligations | ||||||||
| Amortization of debt issuance costs | ||||||||
| Changes in operating assets and liabilities: | ||||||||
| Increase in accounts receivable | ( | ) | ( | ) | ||||
| Decrease (increase) in right-of-use asset | ( | ) | ||||||
| Increase in prepaid expenses | ( | ) | ( | ) | ||||
| (Decrease) increase in accounts payable and accrued expenses | ( | ) | ||||||
| (Decrease) increase in operating lease liability | ( | ) | ||||||
| Settlement of asset retirement obligations | ( | ) | ( | ) | ||||
| Net cash provided by operating activities | ||||||||
| Cash flows from investing activities: | ||||||||
| Additions to oil and gas properties | ( | ) | ( | ) | ||||
| Additions to other property and equipment | ( | ) | ||||||
| Drilling refund | ||||||||
| Investment in limited liability companies at cost | ( | ) | ( | ) | ||||
| Proceeds from sale of oil and gas properties and equipment | ||||||||
| Net cash used in investing activities | ( | ) | ( | ) | ||||
| Cash flows from financing activities: | ||||||||
| Proceeds from exercise of stock options | ||||||||
| Profits from purchase of stock by insider | ||||||||
| Proceeds from long-term debt | ||||||||
| Debt issuance costs | ( | ) | ||||||
| Acquisition of treasury stock | ( | ) | ||||||
| Reduction of long-term debt | ( | ) | ( | ) | ||||
| Net cash used in financing activities | ( | ) | ( | ) | ||||
| Net increase in cash and cash equivalents | ||||||||
| Cash and cash equivalents at beginning of year | ||||||||
| Cash and cash equivalents at end of year | $ | $ | ||||||
| Supplemental disclosure of cash flow information: | ||||||||
| Cash paid for interest | $ | $ | ||||||
| Accrued capital expenditures included in accounts payable | $ | $ | ||||||
| Non-cash investing and financing activities: | ||||||||
| Asset retirement obligations | $ | $ | ||||||
| Operating lease – right of use asset and associated liabilities | $ | $ | ||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
| F-7 |
MEXCO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended March 31, 2023 and 2022
1. Nature of Operations
Mexco Energy Corporation (a Colorado corporation) and its wholly owned subsidiaries, Forman Energy Corporation (a New York corporation), Southwest Texas Disposal Corporation (a Texas corporation) and TBO Oil & Gas, LLC (a Texas limited liability company) (collectively, the “Company”) are engaged in the acquisition, exploration, development and production of crude oil, natural gas, condensate and natural gas liquids (“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas and Southeastern New Mexico; however, the Company owns producing properties and undeveloped acreage in fourteen states. All of the Company’s oil and gas interests are operated by others.
2. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned subsidiaries. All significant intercompany balances and transactions associated with the consolidated operations have been eliminated.
Estimates and Assumptions. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”), management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.
Cash and Cash Equivalents. The Company considers all highly liquid debt instruments purchased with maturities of three months or less and money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally insured limits. At March 31, 2023, the Company had on deposit all of its cash and cash equivalents with three financial institutions. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk.
Accounts
Receivable. Accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended
based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts receivable under joint
operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectibility
of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based
on the Company’s previous loss history. The Company has not experienced any significant credit losses. For the years ended March
31, 2023 and 2022,
Oil and Gas Properties. Oil and gas properties are accounted for using the full cost method of accounting. Under this method of accounting, the costs of unsuccessful, as well as successful, acquisition, exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred. Generally, no gains or losses are recognized on the sale or disposition of oil and gas properties.
Excluded
Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments
in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined
that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of
any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (“DD&A”)
pool). Impairments transferred to the DD&A pool increase the DD&A rate.
| F-8 |
Ceiling Test. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior first day of the month 12-month period held flat for the life of production plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated DD&A. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce stockholders’ equity and reported earnings.
Depreciation, Depletion and Amortization. The depreciable base for oil and gas properties includes the sum of capitalized costs, net of accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production method.
Asset Retirement Obligations. The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using the units of production method. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations.
Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. The Company uses the present value of estimated cash flows related to the ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Income Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.
Other
Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method based
on estimated useful lives of to
Revenue Recognition - Revenue from Contracts with Customers. Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to three months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant.
| F-9 |
Gas Balancing. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when excess takes of natural gas volumes exceed estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced). The Company does not have any significant gas imbalances.
Reclassifications. Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s presentation. These reclassifications had no effect on previously reported results of operations, retained earnings or net cash flows.
Investments.
Liquidity and Capital Resources. Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interest, non-operated properties in areas with significant development potential.
3. Long-Term Debt
On
December 28, 2018, the Company entered into a loan agreement (the “Agreement”) with West Texas National Bank (“WTNB”),
which originally provided for a credit facility of $
On
February 28, 2020, the Agreement was amended to increase the credit facility to $
Under
the Agreement, interest on the facility accrues at a rate equal to the prime rate as quoted in the Wall Street Journal plus one-half
of one percent () floating daily. Interest on the outstanding amount under the Agreement is payable monthly. In addition,
No
principal payments are anticipated to be required through the maturity date of the credit facility,
| F-10 |
Amounts borrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially all of the Company’s oil and gas properties.
In addition, the Agreement prohibits the Company from paying cash dividends on its common stock without prior written permission of WTNB. The Company obtained written permission from WTNB prior to declaring the special dividend on April 10, 2023 as discussed in Note 14. The Agreement does not permit the Company to enter into hedge agreements covering crude oil and natural gas prices without prior WTNB approval.
There was no balance outstanding on the credit facility as of March 31, 2023. The following table is a summary of activity on the WTNB credit facility for the years ended March 31, 2023 and 2022:
| Principal | ||||
| Balance at April 1, 2021: | $ | |||
| Borrowings | ||||
| Repayments | ||||
| Balance at March 31, 2022: | $ | |||
| Borrowings | ||||
| Repayments | ||||
| Balance at March 31, 2023: | $ | |||
4. Asset Retirement Obligations
The Company’s asset retirement obligations relate to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. The fair value of a liability for an ARO is recorded in the period in which it is incurred, discounted to its present value using the credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. The ARO is included on the consolidated balance sheets with the current portion being included in the accounts payable and accrued expenses.
The following table provides a rollforward of the asset retirement obligations for fiscal years ended March 31:
| 2023 | 2022 | |||||||
| Carrying amount of asset retirement obligations, beginning of year | $ | $ | ||||||
| Liabilities incurred | ||||||||
| Liabilities settled | ( | ) | ( | ) | ||||
| Accretion expense | ||||||||
| Revisions | ||||||||
| Carrying amount of asset retirement obligations, end of year | ||||||||
| Less: Current portion | ||||||||
| Non-Current asset retirement obligation | $ | $ | ||||||
5. Income Taxes
On
August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”).
| F-11 |
The Company files a consolidated federal income tax return and various state income tax returns. The amount of income taxes the Company records requires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions, the earliest year open to examination by U.S. federal and state income tax jurisdictions is 2018.
GAAP requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Significant components of net deferred tax assets (liabilities) at March 31 are as follows:
| 2023 | 2022 | |||||||
| Deferred tax assets: | ||||||||
| Percentage depletion carryforwards | $ | $ | ||||||
| Deferred stock-based compensation | ||||||||
| Asset retirement obligation | ||||||||
| Net operating loss | ||||||||
| Other | ||||||||
| Deferred tax liabilities: | ||||||||
| Excess financial accounting bases over tax bases of property and equipment | ||||||||
| Deferred tax asset, net | $ | $ | ||||||
| Valuation allowance | ( | ) | ( | ) | ||||
| Net deferred tax | $ | $ | ||||||
As
of March 31, 2023, the Company has a statutory depletion carryforward of approximately $
A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.
A reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows:
| 2023 | 2022 | |||||||
| Tax expense at federal statutory rate (1) | $ | $ | ||||||
| Statutory depletion carryforward | ( | ) | ||||||
| Change in valuation allowance | ( | ) | ( | ) | ||||
| U. S. tax reform, corporate rate reduction | ||||||||
| Permanent differences | ( | ) | ||||||
| State income expense | ||||||||
| Other | ( | ) | ||||||
| Total income tax | $ | $ | ||||||
| Effective income tax rate | % | % | ||||||
| (1) |
| F-12 |
For
the years ended March 31, 2023 and 2022, the Company did
While the amount of unrecognized tax benefits may change in the next 12 months, the Company does not expect any change to have a significant impact on its results of operations. The recognition of the total amount of the unrecognized tax benefits would have an impact on the effective tax rate. If these unrecognized tax benefits are disallowed, the Company will be required to pay additional taxes.
Based
on the material write-downs of the carrying value of our oil and natural gas properties for the year ending March 31, 2016, we are in
a net deferred tax asset position for years ending March 31, 2023 and 2022. Our deferred tax asset is $
6. Major Customers
Currently, the Company operates exclusively within the United States and its revenues and operating profit are derived from the oil and gas industry. Oil and gas production is sold to various purchasers and the receivables are unsecured. Historically, the Company has not experienced significant credit losses on its oil and gas accounts and management is of the opinion that significant credit risk does not exist. Management is of the opinion that the loss of any one purchaser would not have an adverse effect on the Company’s ability to sell its oil and gas production.
In
fiscal 2023, one purchaser accounted for
7. Oil and Natural Gas Costs
The costs related to the Company’s oil and natural gas activities were incurred as follows for the years ended March 31:
| 2023 | 2022 | |||||||
| Property acquisition costs: | ||||||||
| Proved | $ | $ | ||||||
| Unproved | ||||||||
| Exploration | ||||||||
| Development | ||||||||
| Capitalized asset retirement obligations | ||||||||
| Total costs incurred for oil and gas properties | $ | $ | ||||||
The Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:
| 2023 | 2022 | |||||||
| Proved oil and gas properties | $ | $ | ||||||
| Unproved oil and gas properties: | ||||||||
| subject to amortization | ||||||||
| not subject to amortization | ||||||||
| Less accumulated DD&A | ||||||||
| $ | $ | |||||||
DD&A
amounted to $
| F-13 |
| 2023 | 2022 | |||||||
| Net income | $ | $ | ||||||
| Shares outstanding: | ||||||||
| Weighted avg. common shares outstanding – basic | ||||||||
| Effect of the assumed exercise of dilutive stock options | ||||||||
| Weighted avg. common shares outstanding – dilutive | ||||||||
| Income per common share: | ||||||||
| Basic | $ | $ | ||||||
| Diluted | $ | $ | ||||||
For
the year ended March 31, 2023, shares relating to stock options were excluded from the computation of diluted net income because
their inclusion would be anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $
9. Stockholders’ Equity
In
September 2022, the Board of Directors authorized the use of up to $
On
August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other
tax provisions, establishes a
On September 6, 2022, one of the Company’s directors paid the Company $
In September 2019, the Company adopted the 2019 Employee Incentive Stock Plan (the “2019 Plan”). The 2019 Plan provides for the award of stock options up to shares and includes option awards as well as stock awards. Option awards are granted with the restriction of requiring payment for the shares. Stock awards are granted without restrictions and without payment by the recipient. Neither option awards nor stock awards may exceed shares granted to any one individual in any fiscal year. Stock options may be an incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan are granted at the fair market value of the common stock at the date of grant, become exercisable to the extent of % of the shares optioned on each of four anniversaries of the date of grant, expire ten years from the date of grant and are subject to forfeiture if employment terminates. The 2019 Plan expires from the date of adoption. According to the Company’s employee stock incentive plan, new shares will be issued upon the exercise of stock options and the Company can repurchase shares exercised under the plan.
| F-14 |
During the year ended March 31, 2023, the Compensation Committee of the Board of Directors approved and the Company granted stock options. During the year ended March 31, 2022, the Compensation Committee of the Board of Directors approved and the Company granted stock options. Subsequently, in April 2023, the Compensation Committee approved and the Company granted stock options.
The plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2023 and 2022.
The Company recognized compensation expense of $ and $ related to vesting stock options in general and administrative expense in the Consolidated Statements of Operations for fiscal 2023 and 2022, respectively. The total cost related to non-vested awards not yet recognized at March 31, 2023 totals $, which is expected to be recognized over a weighted average of years.
The fair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are based on historical volatility of the Company’s stock over the contractual term of 120 months and other factors. The Company uses historical data to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. Since the Company has only declared a special one-time dividend, no dividend yield was used in the calculation. Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Binomial model.
| For the year ended March 31, | ||||||||
| 2023 | 2022 | |||||||
| Grant-date fair value | $ | $ | ||||||
| Volatility factor | % | % | ||||||
| Dividend yield | ||||||||
| Risk-free interest rate | % | % | ||||||
| Expected term (in years) | ||||||||
No forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types of awards. During the year ended March 31, 2023, unvested stock options were forfeited due to the resignation of an employee. During the year ended March 31, 2022, there were stock options forfeited or expired.
| Number of Shares | Weighted Average Exercise Price Per Share | Weighted
Aggregate Average Remaining Contract Life in Years | Intrinsic Value | |||||||||||||
| Outstanding at April 1, 2021 | $ | $ | ||||||||||||||
| Granted | ||||||||||||||||
| Exercised | ( | ) | ||||||||||||||
| Forfeited or Expired | ||||||||||||||||
| Outstanding at March 31, 2022 | $ | $ | ||||||||||||||
| Granted | ||||||||||||||||
| Exercised | ( | ) | ||||||||||||||
| Forfeited or Expired | ( | ) | ||||||||||||||
| Outstanding at March 31, 2023 | $ | $ | ||||||||||||||
| Vested at March 31, 2023 | $ | $ | ||||||||||||||
| Exercisable at March 31, 2023 | $ | $ | ||||||||||||||
| F-15 |
During
the year ended March 31, 2023, stock options covering shares were exercised with a total intrinsic value of $. The Company
received proceeds of $
Other information pertaining to option activity was as follows during the year ended March 31:
| 2023 | 2022 | |||||||
| Weighted average grant-date fair value of stock options granted (per share) | $ | $ | ||||||
| Total fair value of options vested | $ | $ | ||||||
| Total intrinsic value of options exercised | $ | $ | ||||||
| Range of Exercise Prices | Number of Options | Weighted Average Exercise Price Per Share | Weighted Average Remaining Contract Life in Years | Aggregate Intrinsic Value | ||||||||||||
| $ – | $ | |||||||||||||||
| – | ||||||||||||||||
| – | ||||||||||||||||
| – | ||||||||||||||||
| – | ||||||||||||||||
| $ – | $ | $ | ||||||||||||||
Outstanding options at March 31, 2023 expire between August 1, 2024 and August 2032 and have exercise prices ranging from $ to $.
11. Related Party Transactions
Related
party transactions for the Company primarily relate to shared office expenditures in addition to administrative and operating expenses
paid on behalf of the principal stockholder. The total billed to and reimbursed by the stockholder for the years ended March 31, 2023
and 2022 were $ and $, respectively. The principal stockholder pays for his share of the lease amount for the shared office
space directly to the lessor. Amounts paid by the principal stockholder directly to the lessor for the year ending March 31, 2023 and
2022 were $
12. Leases
The
Company leases approximately
The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets.
| F-16 |
Operating
lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent
its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement
date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate,
the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value
of lease payments. The incremental borrowing rate used at adoption was
The balance sheets classification of lease assets and liabilities was as follows:
| March 31, 2023 | ||||
| Assets | ||||
| Operating lease right-of-use asset, beginning balance | $ | |||
| Current period amortization | ( | ) | ||
| Lease amendment | ||||
| Total operating lease right-of-use asset | $ | |||
| Liabilities | ||||
| Operating lease liability, current | $ | |||
| Operating lease liability, long term | ||||
| Total lease liabilities | $ | |||
Future minimum lease payments as of March 31, 2023 under non-cancellable operating leases are as follows:
| Lease Obligation | ||||
| Fiscal Year Ended March 31, 2024 | $ | |||
| Fiscal Year Ended March 31, 2025 | ||||
| Total lease payments | $ | |||
| Less: imputed interest | ( | ) | ||
| Operating lease liability | ||||
| Less: operating lease liability, current | ( | ) | ||
| Operating lease liability, long term | $ | |||
Net
cash paid for our operating lease for the year ended March 31, 2023 and 2022 was $
13. Oil and Gas Reserve Data (Unaudited)
The estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The estimates as of March 31, 2023 and 2022 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The services provided by Russell K. Hall and Associates, Inc. are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
| F-17 |
The following table presents the weighted average first-day-of-the-month prices used for oil and gas reserve preparation, based upon SEC guidelines.
| March 31, | ||||||||||||
| 2023 | 2022 | % Change | ||||||||||
| Prices utilized in the reserve estimates before adjustments: | ||||||||||||
| Oil per Bbl | $ | $ | % | |||||||||
| Natural gas per MMBtu | $ | $ | % | |||||||||
The
Company’s total estimated proved reserves at March 31, 2023 were approximately
Changes in Proved Reserves:
| Oil
(Bbls) | Natural
Gas (Mcf) | |||||||
| Proved Developed and Undeveloped Reserves: | ||||||||
| As of April 1, 2021 | ||||||||
| Revision of previous estimates | ( | ) | ( | ) | ||||
| Purchase of minerals in place | ||||||||
| Extensions and discoveries | ||||||||
| Sales of minerals in place | ( | ) | ||||||
| Production | ( | ) | ( | ) | ||||
| As of March 31, 2022 | ||||||||
| Revision of previous estimates | ( | ) | ||||||
| Purchase of minerals in place | ||||||||
| Extensions and discoveries | ||||||||
| Sales of minerals in place | ||||||||
| Production | ( | ) | ( | ) | ||||
| As of March 31, 2023 | ||||||||
Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves (“PUD”) are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion within five years of the date of their initial recognition. Moreover, the Company may be required to write down its proved undeveloped reserves if the operators do not drill on the reserves within the required five-year timeframe. Such downward revisions are primarily the result of reserves written off due to the five-year limitation and the change in the timing of new development. They are primarily royalty interests on leases in Loving, Pecos and Ward Counties, Texas which are held by production and still in place to be developed in the future.
Summary of Proved Developed and Undeveloped Reserves as of March 31, 2023 and 2022:
| Oil
(Bbls) | Natural
Gas (Mcf) | |||||||
| Proved Developed Reserves: | ||||||||
| As of April 1, 2021 | ||||||||
| As of March 31, 2022 | ||||||||
| As of March 31, 2023 | ||||||||
| Proved Undeveloped Reserves: | ||||||||
| As of April 1, 2021 | ||||||||
| As of March 31, 2022 | ||||||||
| As of March 31, 2023 | ||||||||
At
March 31, 2023,
| F-18 |
The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2023.
Progress of Converting Proved Undeveloped Reserves:
| Oil & Natural Gas | Future | |||||||
| (BOE) | Development Costs | |||||||
| PUDs, beginning of year | $ | |||||||
| Revision of previous estimates | ( | ) | ||||||
| Sales of reserves | ||||||||
| Conversions to PD reserves | ( | ) | ( | ) | ||||
| Additional PUDs added | ||||||||
| PUDs, end of year | $ | |||||||
Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2023 and 2022 along with estimates of the operating costs, production taxes and future development costs necessary to produce such reserves. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.
Operating
costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development
costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The
future cash flows estimated to be spent to develop the Company’s share of proved undeveloped properties through March 31, 2027
are $
Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards.
The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.
The
current reporting rules require that year end reserve calculations and future cash inflows be based on the 12-month average market prices
for sales of oil and gas on the first calendar day of each month during the fiscal year discounted at
The
standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first day of
the month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements)
to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year end costs)
to be incurred in developing and producing the proved reserves, discounted using a rate of
The basis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of proved oil and gas properties.
| F-19 |
The
following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future
Net Cash Flows as of March 31, 2023 and 2022 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which
requires the use of a
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
| March 31 | ||||||||
| 2023 | 2022 | |||||||
| Future cash inflows | $ | $ | ||||||
| Future production costs and taxes | ( | ) | ( | ) | ||||
| Future development costs | ( | ) | ( | ) | ||||
| Future income taxes | ( | ) | ( | ) | ||||
| Future net cash flows | ||||||||
| Annual 10% discount for estimated timing of cash flows | ( | ) | ( | ) | ||||
| Standardized measure of discounted future net cash flows | $ | $ | ||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
| March 31 | ||||||||
| 2023 | 2022 | |||||||
| Sales of oil and gas produced, net of production costs | $ | ( | ) | $ | ( | ) | ||
| Net changes in price and production costs | ( | ) | ||||||
| Changes in previously estimated development costs | ( | ) | ||||||
| Revisions of quantity estimates | ( | ) | ( | ) | ||||
| Net change due to purchases and sales of minerals in place | ||||||||
| Extensions and discoveries, less related costs | ||||||||
| Net change in income taxes | ( | ) | ( | ) | ||||
| Accretion of discount | ||||||||
| Changes in timing of estimated cash flows and other | ( | ) | ||||||
| Changes in standardized measure | ||||||||
| Standardized measure, beginning of year | ||||||||
| Standardized measure, end of year | $ | $ | ||||||
14. Subsequent Events
On April 10, 2023, the Company announced that its Board of Directors declared a special dividend of $ per common share to its shareholders of record at the close of business on May 1, 2023. The special dividend was paid on May 15, 2023.
In
April 2023, the Company expended approximately $
In
May 2023, the Company expended approximately $
In
June 2023, the Company received approximately $
The Company completed a review and analysis of all events that occurred after the consolidated balance sheet date to determine if any such events must be reported and has determined that there are no other subsequent events to be disclosed.
| F-20 |
INDEX TO EXHIBITS
| 36 |
EXHIBIT 10.5
EXECUTION VERSION
SECOND AMENDMENT TO LOAN AGREEMENT
This Second Amendment to Loan Agreement (this “Second Amendment”) is entered into as of the 28th day of March, 2023, by and among MEXCO ENERGY CORPORATION, a Colorado corporation (“Mexco”), FORMAN ENERGY CORPORATION, a New York corporation (“Forman”), SOUTHWEST TEXAS DISPOSAL CORPORATION, a Texas corporation (“Southwest”), and TBO OIL & GAS, LLC, a Texas limited liability company (“TBO”, and together with Mexco, Forman and Southwest, collectively, the “Borrowers” or individually a “Borrower”), and WEST TEXAS NATIONAL BANK, a national bank, as lender (the “Lender”).
Recitals:
A. The Borrowers and the Lender entered into that certain Loan Agreement dated as of December 28, 2018 (the “Original Loan Agreement”), as amended by that certain First Amendment to Loan Agreement dated as of February 28, 2020 by and among the Borrowers and the Lender (the “First Amendment”; and the Original Loan Agreement, as amended by the First Amendment, the “Loan Agreement”).
B. Pursuant to the terms of the Original Loan Agreement, (i) the Lender provided the Borrowers a revolving line of credit loan with a Commitment (as defined in the Original Loan Agreement) in the initial amount of $1,000,000.00 (the “Original RLOC Loan”), and (ii) the Borrowers executed that certain Revolving Line of Credit Promissory Note dated as of December 28, 2018 in the face amount of $1,000,000.00, payable to the order of the Lender (the “Original Note”).
C. Pursuant to the terms of the First Amendment, among other matters set forth therein, (i) the Lender increased the Commitment (as defined in the Original Loan Agreement) for the revolving line of credit loan to the Borrowers to $2,500,000.00 (the “RLOC Loan”), and (ii) the Borrowers executed that certain Revolving Line of Credit Promissory Note dated as of February 28, 2020 in the face amount of $2,500,000.00, payable to the order of the Lender (the “Prior Note”), which was given in amendment, restatement, renewal, extension and modification, but not extinguishment or novation, of the Original Note.
D. The Borrowers and the Lender desire to amend the Loan Agreement to, among other matters, extend the maturity date of the RLOC Loan.
E. Contemporaneously with the execution of this Second Amendment, the Borrowers have executed and delivered to the Lender that certain Revolving Line of Credit Promissory Note dated of even date herewith in the face amount of $2,500,000.00, payable to the order of the Lender (the “Note”), which Note is given in amendment, restatement, renewal, extension and modification, but not extinguishment or novation, of the Original Note and the Prior Note.
NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and other good and valuable consideration, it is hereby agreed among the Lender and the Borrowers as follows:
Agreement:
1. Capitalized terms used but not defined herein shall have the respective meanings ascribed thereto in the Loan Agreement.
2. The definition of the defined term “Note” set forth in Section 1.1 of the Loan Agreement is hereby amended in its entirety to read as follows:
“ ‘Note’ means that certain revolving line of credit promissory note in the face amount of $2,500,000.00, dated as of March 28, 2023, made by the Borrowers payable to the order of the Lender, in substantially the form attached hereto as Exhibit I, together with all deferrals, renewals or extensions thereof, which promissory note shall evidence the Advances made to the Borrowers by the Lender pursuant to Section 2.1.”
3. Section 2.3 of the Loan Agreement is hereby amended in its entirety to read as follows:
“2.3 Repayment Provisions. Interest, computed on the unpaid principal balance of the Note, shall be due and payable in monthly installments, with the first of such installments to be paid on April 28, 2023, and subsequent installments to be paid on the twenty-eighth day of each month thereafter. All of the outstanding principal and accrued, unpaid interest hereunder shall be due and payable in full on March 28, 2026, being the date of final maturity hereunder. All payments of principal and interest required under the Note shall be made in immediately available funds, and shall be made at Lender’s principal banking offices in Midland, Texas, provided, however, the Lender may, upon thirty (30) day’s written notice to the Borrowers, designate a different place of payment. If a payment under the Note is received by the Lender more than ten (10) days after it is due, the Borrowers agree to pay a late charge to the Lender equal to five percent (5%) of the delinquent amount.”
4. Pursuant to Section 2.7 of the Loan Agreement, the amount of the Borrowing Base under the Loan Agreement shall remain at $1,500,000.00 until redetermined by the Lender in accordance with Section 2.7 of the Loan Agreement.
5. Exhibit I to the Loan Agreement is hereby replaced with Exhibit I attached hereto.
6. The effectiveness of this Second Amendment shall be subject to the following conditions precedent: (a) the Borrowers shall have executed and delivered to the Lender this Second Amendment, the Note, amendments to the Deed of Trust, and all other required documents, all in form and substance satisfactory to the Lender, and (b) the Borrowers shall have paid to the Lender a renewal fee in the amount of $9,000.00.
7. As an inducement to the Lender to enter into this Second Amendment, the Borrowers represent and warrant to the Lender that (a) the representations and warranties contained in the Loan Agreement and the other Loan Documents are true and correct as of the date hereof, (b) none of the Borrowers has breached any of the covenants contained in the Loan Agreement or the other Loan Documents (except as may have been waived in writing by the Lender), and (c) no default or Event of Default now exists, nor does there exist any condition or event which, with notice and/or lapse of time, would constitute a default or Event of Default under the Loan Agreement or any of the other Loan Documents.
8. Neither the execution by the Lender of this Second Amendment nor anything contained herein shall in any way be construed or operate as a waiver by the Lender of any default or Event of Default (whether now existing or that may occur hereafter) or of any of the Lender’s rights under the Loan Agreement as hereby amended or under any of the other Loan Documents.
9. Except as provided herein, all terms and provisions of the Loan Agreement shall remain unchanged. The Borrowers hereby ratify, affirm and reaffirm all of the terms and provisions of the Loan Agreement, as amended hereby, of the Note and of the other Loan Documents to the extent each is a party thereto.
10. This Second Amendment may be executed in any number of identical separate counterparts (including by electronic or facsimile transmission), each of which for all purposes is to be deemed an original but all of which shall constitute, collectively, one agreement.
11. Each of the Loan Documents is hereby amended so that any reference in the Loan Documents to the Loan Agreement shall mean a reference to the Loan Agreement as amended hereby and any reference in the Loan Documents to the Prior Note shall mean a reference to the Note (as defined herein). This Second Amendment, the Note, the amendments to the Deed of Trust, and all other documents executed in connection with this Second Amendment constitute Loan Documents under the Loan Agreement.
12. THIS SECOND AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK. SIGNATURE PAGES FOLLOW.]
IN WITNESS WHEREOF, the parties hereto have caused this instrument to be duly executed effective as of the date first above written.
| BORROWERS: | ||
| MEXCO ENERGY CORPORATION | ||
| By: | /s/ Nicholas C. Taylor | |
| Nicholas C. Taylor | ||
| Chairman of the Board and | ||
| Chief Executive Officer | ||
| FORMAN ENERGY CORPORATION | ||
| By: | /s/ Nicholas C. Taylor | |
| Nicholas C. Taylor | ||
| Chairman of the Board and | ||
| Chief Executive Officer | ||
| SOUTHWEST TEXAS DISPOSAL CORPORATION | ||
| By: | /s/ Nicholas C. Taylor | |
| Nicholas C. Taylor | ||
| Chairman of the Board and | ||
| Chief Executive Officer | ||
| TBO OIL & GAS, LLC | ||
| By: | /s/ Nicholas C. Taylor | |
| Nicholas C. Taylor | ||
| Chairman of the Board and | ||
| Chief Executive Officer | ||
| LENDER: | ||
| WEST TEXAS NATIONAL BANK | ||
| By: | /s/ Frank K. Stowers Frank K. Stowers | |
| Executive Vice President | ||
| WEST TEXAS NATIONAL BANK | ||
| By: | /s/ Garrett Robinson Garrett Robinson | |
| Portfolio Manager | ||
Exhibit I
Form of Note
REVOLVING LINE OF CREDIT PROMISSORY NOTE
| $2,500,000.00 | ______________, 2023 |
1. For value received, MEXCO ENERGY CORPORATION, a Colorado corporation (“Mexco”), FORMAN ENERGY CORPORATION, a New York corporation (“Forman”), SOUTHWEST TEXAS DISPOSAL CORPORATION, a Texas corporation (“Southwest”), and TBO OIL & GAS, LLC, a Texas limited liability company (“TBO”, and together with Mexco, Forman and Southwest, collectively, the “Makers” or individually a “Maker”), jointly and severally, promise to pay to the order of WEST TEXAS NATIONAL BANK, a national bank (the “Lender”), at its offices at 6 Desta Dr., Suite 2400, Midland, Texas 79705, in lawful money of the United States of America, the principal sum of TWO MILLION FIVE HUNDRED THOUSAND AND NO/100 DOLLARS ($2,500,000.00), or so much thereof as may be advanced and outstanding at any time or from time to time pursuant to the Loan Agreement (as hereinafter defined), together with interest on the principal amount from time to time outstanding hereunder, from the date of the disbursement of such principal until maturity, at an annual rate of interest which shall from day to day be equal to the lesser of (a) the Wall Street Journal Prime Rate in effect on such date (calculated on the basis of actual days elapsed, but computed as if each calendar year consisted of 360 days), plus one half of one percent (0.50%), or (b) the Highest Lawful Rate; provided, however, all past due principal and interest on this Note will bear interest from the maturity thereof until paid, at the Default Rate, as defined in the Loan Agreement.
2. This Note is executed pursuant to the terms of that certain Loan Agreement, dated as of December 28, 2018, by and among the Makers, as borrowers, and the Lender, as lender, as amended by that certain First Amendment to Loan Agreement, dated as of February 28, 2020, by and among the Makers, as borrowers, and the Lender, as lender, as further amended by that certain Second Amendment to Loan Agreement, dated of even date herewith, by and among the Makers, as borrowers, and the Lender, as lender, as the same may be further amended, restated, extended or otherwise modified from time to time (the “Loan Agreement”). This Note incorporates by reference the terms of the Loan Agreement. In the event of a conflict between the terms of this Note and the terms of the Loan Agreement, the terms of the Loan Agreement will be deemed to be controlling. Capitalized terms not defined in this Note shall have the meaning given to such terms in the Loan Agreement. This is a Revolving Line of Credit Promissory Note. Accordingly, it is contemplated that there will be Advances and payments on this Note from time to time, but no Advances or payments (including total payment of the unpaid principal balance outstanding prior to maturity) shall affect or impair the validity or enforceability of this Note as to future Advances hereunder. Notwithstanding the face amount of this Note, in no event shall the outstanding principal amount of all Advances made hereunder at any time exceed the lesser of (i) the Commitment or (ii) the Borrowing Base then in effect. Reference is made to the Loan Agreement for further statements regarding the obligation of Lender to make Advances hereunder.
3. Interest, computed on the unpaid principal balance of this Note, shall be due and payable in monthly installments, with the first of such installments to be paid on April 28, 2023, and subsequent installments to be paid on the twenty-eighth day of each month thereafter. All of the outstanding principal and accrued, unpaid interest hereunder shall be due and payable in full on March 28, 2026, being the date of final maturity hereunder. All payments of principal and interest required under this Note shall be made in immediately available funds, and shall be made at Lender’s principal banking offices in Midland, Texas, provided, however, the Lender may, upon thirty (30) day’s written notice to the Makers, designate a different place of payment. If a payment under this Note is received by the Lender more than ten (10) days after it is due, the Makers agree to pay a late charge to the Lender equal to five percent (5%) of the delinquent amount.
4. If an Event of Default should occur under the terms of the Loan Agreement, thereupon at the option of Lender, the principal balance and accrued interest of this Note will become and be due and payable forthwith without presentment, demand, notice of default, protest, notice of protest or dishonor, notice of nonpayment, notice of acceleration or the intent to accelerate, or other notice of any kind, all of which are hereby expressly waived by each Maker and each other liable party. Lender may waive any default without waiving any prior or subsequent default.
5. To the extent not prohibited by applicable Law, Makers will pay all costs and expenses and reimburse Lender for any and all expenditures of every character incurred or expended from time to time, regardless of whether a default or Event of Default will have occurred, in connection with Lender exercising any of its rights and remedies under this or any other instrument now or hereafter securing the indebtedness evidenced hereby or at Law, including, without limitation, all filing fees, taxes, brokerage fees and commissions, title review and abstract fees, Uniform Commercial Code search fees, other fees and expenses incident to title searches, reports and security interests, escrow fees, attorneys’ fees, legal expenses, and court costs, provided, however, that no right or option granted by Makers or Lender or otherwise arising pursuant to any provision of this or any other instrument will be deemed to impose or admit a duty on Lender to supervise, monitor or control any aspect of the character or condition of the assets of Makers or any operations conducted in connection with it for the benefit of any Maker or any other person or entity other than Lender.
6. If this Note is not paid at maturity whether by acceleration or otherwise and is placed in the hands of an attorney for collection, or suit is filed hereon, or proceedings are had in probate, bankruptcy, receivership, reorganization, arrangement or other legal proceedings for collection hereof, Makers and each other liable party agree to pay Lender its collection costs, including a reasonable amount for attorneys’ fees, but in no event to exceed the maximum amount permitted by Law. Each Maker and each other liable party are and will be directly and primarily, jointly and severally, liable for the payment of all sums called for hereunder, and each Maker and each other liable party hereby expressly waive bringing of suit and diligence in taking any action to collect any sums owing hereon and in the handling of any security, and each Maker and each other liable party hereby consent to and agree to remain liable hereon regardless of any renewals, extensions for any period or rearrangements hereof, or partial prepayments hereon, or any release or substitution of security hereof, in whole or in part, with or without notice, from time to time, before or after maturity.
7. It is the intention of the parties hereto to comply strictly with the applicable usury Laws as in effect from time to time; and in this connection, there shall never be taken, reserved, contracted for, collected, charged or received on this Note or any other Obligations interest in excess of that which would accrue at the Highest Lawful Rate. For purposes of Chapter 303 of the Texas Finance Code, as amended, the Makers agree that the Highest Lawful Rate shall be the “weekly rate ceiling” as defined in such chapter, provided that the Lender may also rely, to the extent permitted by applicable Laws, on alternative maximum rates of interest under such other applicable Laws, if greater.
If under any circumstances the aggregate amount paid on the Obligations includes amounts that are by Law deemed to be interest which exceed the Highest Lawful Rate (the “Excess Interest”), the Makers and the Lender stipulate that such payment and collection will have been and will be deemed to have been, to the fullest extent permitted by applicable Laws, the result of mathematical error on the part of the Makers and the Lender, and the Lender shall promptly credit the amount of such Excess Interest on the principal amount of the outstanding Obligations, or if the principal amount of the Obligations shall have been paid in full, refund the Excess Interest to the Makers. In the event that the maturity of this Note is accelerated by reason of an election of the Lender resulting from any Event of Default, or in the event of any prepayment, then such consideration that constitutes interest under Laws applicable to the Lender may never exceed the Highest Lawful Rate, and Excess Interest, if any, provided for in this Note, the Loan Agreement or otherwise shall be canceled automatically by the Lender as of the date of such acceleration or prepayment and, if theretofore paid, shall be credited by the Lender on the principal amount of the Obligations, or if the principal amount of the Obligations shall have been paid in full, refunded by the Lender to the Makers.
All sums paid, or agreed to be paid, to the Lender for the use, forbearance, and detention of the proceeds of the Loan shall, to the extent permitted by applicable Law, be amortized, prorated, allocated, and spread throughout the full term of the Obligations until paid in full so that the actual rate of interest is uniform, but does not exceed the Highest Lawful Rate, throughout the full term hereof.
8. Makers reserve the option of prepaying the principal of this Note, in whole or in part, at any time after the date hereof without penalty. At the option of Lender, it may demand (at any time at or after prepayment) all accrued and unpaid interest with respect to the principal amount prepaid through the date of prepayment. All amounts of principal so prepaid and received by the owner and holder of this Note will be applied to the last maturing installments of this Note in their inverse order of maturity.
9. This Note is secured by the Security Documents described in the Loan Agreement.
10. Lender reserves the right, exercisable in Lender’s sole discretion and without notice to Makers or any other person, to sell participations, to assign its interest or both, in all or any part of this Note or the debt evidenced by this Note.
11. This Note shall be governed by and construed in accordance with the Laws of the United States of America and the State of Texas, except to the extent the location or nature of the collateral securing this Note requires the application of the Laws of other jurisdictions to be applied as to matters of creation, perfection and priority of liens and the rights of Lender upon default.
12. This Note is given in amendment, restatement, renewal, extension and modification, but not extinguishment or novation, of (i) that certain Revolving Line of Credit Promissory Note dated as of December 28, 2018 in the face amount of $1,000,000.00, made by Makers and payable to the order of Lender, and (ii) that certain Revolving Line of Credit Promissory Note dated as of February 28, 2020 in the face amount of $2,500,000.00, made by Makers and payable to the order of Lender.
13. By execution of this Note, each Maker acknowledges the receipt of the following notices from Lender:
“THE LOAN AGREEMENT, THIS NOTE, AND ALL OTHER LOAN DOCUMENTS EXECUTED HEREWITH TOGETHER CONSTITUTE A WRITTEN LOAN AGREEMENT WHICH REPRESENTS THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.”
“THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.”
[Signature Page Follows]
Effective as of the date first above written.
| MAKERS: | ||
| MEXCO ENERGY CORPORATION | ||
| By: | ||
| Nicholas C. Taylor | ||
| Chairman of the Board and | ||
| Chief Executive Officer | ||
| FORMAN ENERGY CORPORATION | ||
| By: | ||
| Nicholas C. Taylor | ||
| Chairman of the Board and | ||
| Chief Executive Officer | ||
| SOUTHWEST TEXAS DISPOSAL CORPORATION | ||
| By: | ||
| Nicholas C. Taylor | ||
| Chairman of the Board and | ||
| Chief Executive Officer | ||
| TBO OIL & GAS, LLC | ||
| By: | ||
| Nicholas C. Taylor | ||
| Chairman of the Board and | ||
| Chief Executive Officer | ||
By its signature, Lender acknowledges the truth of the notice hereinabove stated.
| LENDER: | ||
| WEST TEXAS NATIONAL BANK | ||
| By: | ||
| Frank K. Stowers | ||
| Executive Vice President | ||
| WEST TEXAS NATIONAL BANK | ||
| By: | ||
| Garrett Robinson | ||
| Portfolio Manager | ||
EXHIBIT 21.1
SUBSIDIARIES OF MEXCO ENERGY CORPORATION
| 1. | Forman Energy Corporation, a New York corporation |
| 2. | Southwest Texas Disposal Corporation, a Texas corporation |
| 3. | TBO Oil & Gas, LLC, a Texas limited liability company |
EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (File No. 333-165296) of Mexco Energy Corporation of our report dated June 26, 2023, relating to the consolidated financial statements which appear in this Form 10-K for the year ended March 31, 2023.
/s/ WEAVER AND TIDWELL, L.L.P.
Midland, Texas
June 26, 2023
EXHIBIT 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
As independent engineering consultants, Russell K. Hall and Associates, Inc. hereby consents to the use of the name Russell K. Hall and Associates, Inc. and references to Russell K. Hall and Associates, Inc. and to the inclusion of and references to our report, or information contained therein, entitled “Evaluation of Oil and Gas Reserves of Mexco Energy Corporation Effective March 31, 2023” prepared for Mexco Energy Corporation in the Annual Report on Form 10-K of Mexco Energy Corporation for the year ended March 31, 2023.
/s/ Russell K. Hall and Associates, Inc.
PETROLEUM AND ENVIRONMENTAL ENGINEERING CONSULTANTS
Midland, Texas
June 26, 2023
Exhibit 31.1
CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER
I, Nicholas C. Taylor, certify that:
1. I have reviewed this annual report on Form 10-K of Mexco Energy Corporation;
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have: |
| a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| c) | evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| d) | disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
| June 26, 2023 | /s/ Nicholas C. Taylor |
| Nicholas C. Taylor | |
| Chief Executive Officer |
Exhibit 31.2
CERTIFICATION OF THE CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Tamala L. McComic, certify that:
1. I have reviewed this annual report on Form 10-K of Mexco Energy Corporation;
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have: |
| a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| c) | evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| d) | disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
| June 26, 2023 | /s/ Tamala L. McComic |
| Tamala L. McComic | |
| Chief Financial Officer, President, Treasurer, and Assistant Secretary |
Exhibit 32.1
CERTIFICATION OF CEO AND CFO PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Mexco Energy Corporation (the “Company”) on Form 10-K for the year ending March 31, 2023, as filed with the SEC on the date hereof (the “Report”), we, Nicholas C. Taylor, Chief Executive Officer and Tamala L. McComic, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to our knowledge:
| (1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
| (2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
| Dated: June 26, 2023 | /s/ Nicholas C. Taylor |
| Chairman of the Board and | |
| Chief Executive Officer | |
| Dated: June 26, 2023 | /s/ Tamala L. McComic |
| Chief Financial Officer, President, | |
| Treasurer and Assistant Secretary |
Exhibit 99.1
RUSSELL K. HALL & ASSOCIATES, INC.
303 West Wall Street, Suite 1102
Midland, Texas 79701
(432) 683-6622
June 16, 2023
Mexco Energy Corporation
Tammy McComic, President
P.O. Box 10502
Midland, Texas 79701
| Re: | Evaluation of Oil and Gas Reserves to the interests of Mexco Energy Corporation Effective March 31, 2023 |
Ms. McComic,
In accordance with your request, we have estimated the extent and value of domestic proved crude oil, condensate and gas reserves owned by Mexco Energy Corporation as of March 31, 2023. The properties to which proved reserves are attributable are located in the states of Alabama, Arkansas, Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, Virginia and Wyoming (as shown in Figure 1) with the majority of the value in New Mexico and Texas. The estimated reserves are based on a detailed study of properties owned by Mexco Energy Corporation. During this study, we consulted freely with the officers and employees of Mexco Energy Corporation and were given access to such records, geological and engineering reports, and other data as were desired for examination. In preparation of this report, we have relied, without independent verification, upon information furnished by Mexco Energy Corporation with respect to property interest owned by it, production from such properties, current costs of operation, current prices for production agreements relating to current and future operation and various other information and data which were accepted as represented. The results of our third-party study, completed on June 16, 2023, are presented herein. The properties reviewed by Russell K. Hall & Associates represent 98% of the total net proved reserves of Mexco Energy Corporation.
The summary below includes Forman Energy, Southwest Texas Disposal Corporation and TBO Oil & Gas, LLC, which are wholly owned subsidiaries of Mexco Energy Corporation. Thirteen (13) Minor Net Income Streams have been evaluated in this report by projecting an oil and gas stream and applying an oil and gas price. Twelve (12) joint ventures have been projected as income streams because it was not economical to project all the properties on an individual basis. There are twenty-six (26) other minor income and unit properties which have also been projected as income streams. Income streams have been converted to barrels of oil and MCF’S of gas based on their ratio of income. Where multiple gas wells with small interest exist, production has been summarized to reduce the cost of the evaluation. It was not considered necessary to make a field examination of the physical condition and operation of the properties in which Mexco Energy Corporation owns an interest.
We estimate the Net Proved Reserves, Future Net Revenue, and the Present Value of Future Net Revenue from the properties of Mexco Energy Corporation as of March 31, 2023 to be as follows:
| Classification of Reserves | Oil
and Condensate (MBBL) | Gas
(MMCF) | Future
Net Revenue (M$) | Present Value Discounted at 10 % (M$) | ||||||||||||
| Proved Developed: | ||||||||||||||||
| Producing | 451 | 3,826 | 45,317 | 26,972 | ||||||||||||
| Non-Producing | 36 | 145 | 2,529 | 1,532 | ||||||||||||
| 487 | 3,971 | 47,846 | 28,504 | |||||||||||||
| Proved Undeveloped | 240 | 978 | 19,045 | 10,969 | ||||||||||||
| Total Proved | 727 | 4,949 | 66,891 | 39,473 | ||||||||||||
The following table sets forth the changes in total Proved Reserves owned by Mexco Energy Corporation as of March 31, 2023.
| Net
Liquid (MBBL) | Net
Gas (MMCF) | |||||||
| Total Proved Reserves Developed and Undeveloped: | ||||||||
| Beginning of Period March 31, 2022 | 809 | 4,842 | ||||||
| Revisions of Previous Estimates | (108 | ) | (328 | ) | ||||
| Beginning of Period as Revised | 701 | 5,170 | ||||||
| Additions from Drilling and Purchase | 31 | 125 | ||||||
| Extensions | 69 | 188 | ||||||
| Sales of Minerals-in-Place | 0 | 0 | ||||||
| Production | (74 | ) | (534 | ) | ||||
| End of Period March 31, 2023 | 727 | 4,949 | ||||||
| Proved Developed Reserves: | ||||||||
| Beginning of Period March 31, 2022 | 429 | 3,583 | ||||||
| End of Period March 31, 2023 | 487 | 3,971 | ||||||
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s (“SEC”) Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Definitions of Oil and Gas Reserves” is included as an attachment to this report. Reserves for the producing properties were determined by extrapolation of the production decline trends, where applicable, analogy with similar offset wells, by volumetric calculations using basic reservoir parameters such as porosity, water saturation, net pay thickness, and estimated areal extent of the reservoir, or by material balance calculations. Reserves for the Proved Developed Non-Producing and Proved Undeveloped properties were determined by volumetric calculations and/or by analogy with offset wells.
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. Moreover, estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts.
The estimates of reserves presented herein were based upon a detailed study of the properties in which Mexco owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.
Where wells did not have significant income to Mexco during 2023, wells have been combined into an income stream in their respective Joint Venture and evaluated as a single projection. This eliminated a significant amount of paper in the Report without detracting from the accuracy of the numbers.
Numerous Proved Undeveloped locations have been added to Mexco’s Drilling Program in the March 31, 2023 SEC Report in which Mexco has an interest.
| 1) | Chesapeake Energy, ConocoPhillips, BTA Oil Producers, Diamondback Energy, Marathon Oil Corporation, and Pioneer Natural Resources all have continual drilling programs. |
| 2) | Several other horizontal wells have been scheduled to be drilled in the future by companies where Mexco has an interest. |
To estimate economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined as of the effective date of the report. Mexco has informed us that they have furnished us all of the accounts, records, geological and engineering data, reports and other data required for this investigation. In preparing our forecast of future production and income, we have relied upon data furnished by Mexco with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, geological structural and isopach maps, well logs, core analyses, and pressure measurements. Russell K. Hall & Associates reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data supplied by Mexco.
Property identification, expense and revenue interests, actual product prices, and operating expenses were provided by Mexco Energy Corporation. This data was not verified by inspection of internal records and files, nor was a physical inspection made of the properties. Information regarding prices and the particular pricing categories under current governmental regulations was supplied by Mexco Energy Corporation.
Net oil and gas reserves are estimated quantities of crude oil, natural gas, and natural gas liquids attributed to the revenue interests of Mexco Energy Corporation. Net income to the interests of Mexco Energy Corporation is the future net revenue after deduction of state and county taxes, operating expenses, and investments, if applicable. The resulting net income is before federal income tax and does not consider any encumbrances against the properties, if such exist. Minor variations in composite columns totals result from computer rounding. Values of the estimated net proved reserves are expressed in terms of future net revenue and present value of future net revenue. Future net revenues are calculated by deducting estimated operating expenses, capital costs, and severance and ad valorem taxes from the future gross revenue.
Present value of future net revenue is calculated by discounting the future net revenue at the rate of ten percent (10%) per annum compounded monthly over the expected period of realization. The present value set forth in this report does not necessarily represent the fair market value of the evaluated interests.
A summary projection of the estimated future net revenue and present value of future net revenue as of March 31, 2023 is as follows:
| Year | Proved
Developed Future Net Revenue $ | Discounted at 10% $ | ||||||
| 2024 | 8,148,870 | 7,788,935 | ||||||
| 2025 | 5,782,437 | 5,026,706 | ||||||
| 2026 | 4,394,546 | 3,470,561 | ||||||
| Remaining | 29,520,305 | 12,217,926 | ||||||
| Total | 47,846,158 | 28,504,128 | ||||||
The future net revenue set forth above reflects estimated capital expenditures in the amount of $441,519.00 necessary to develop those reserves classified as Proved Developed Producing and Proved Developed Non-Producing. Proved Undeveloped net revenue reflects estimated capital costs of $3,837,540.00 to drill and complete those wells.
Estimated reserves and future net income amounts presented in this report, as of March 31, 2023, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the twelve (12) month period prior to the ending date of the period covered in this report (determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations). The benchmark price of $87.45 per barrel has been adjusted by lease for gravity, transportation fees and regional price differentials to an average of $92.02. Gas prices per thousand cubic feet (MCF) are based on a benchmark price of $5.96 per MCF and have been adjusted by lease for BTU content, transportation fees and regional price differentials to an average of $5.675. The oil and gas prices were held constant for the economic life of the properties as specified by the SEC. Oil volumes shown herein are expressed in barrels, which are equivalent to forty-two (42) United States gallons. Gas volumes are expressed at standard conditions of sixty degrees (60°) Fahrenheit and at the standard pressure base of the respective area in which the reserves are located.
Operating expenses including direct and indirect overhead expenses were held constant for the life of all properties except new horizontal wells. Operating expenses for new horizontal wells were held constant for six (6) months then reduced by fifty (50) percent and held constant for the life of the properties. Severance and ad valorem taxes were deducted in the lease reserves and economics projections at the standard state rates or rates provided by Mexco Energy Corporation.
Russell K. Hall & Associates is an Independent Petroleum Engineering Consulting Firm that has been providing Petroleum Consulting Services throughout the world for forty-eight (48) years. Russell K. Hall & Associates does not have any financial interest, including stock ownership in Mexco. Our fees were not contingent on the results of our evaluation. Russell K. Hall & Associates has used all procedures and methods that it considered necessary to prepare this report. The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualification, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
This report is solely for the information of and assistance to Mexco Energy Corporation for their use in SEC filings. It is not to be used, circulated, quoted, or otherwise referred to for any purpose without the express written consent of the undersigned except as required by law. Data utilized in this report will be maintained in our files and is available for your use.
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the SEC Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
It has been our privilege to serve you by preparing this evaluation.
| Yours very truly, | |
| Russell K. Hall & Associates | |
| Texas P. E. no. 69926 | |
| Russell K. Hall and Associates, Inc. | |
| Registration No. F-022199 |
Consolidated Balance Sheets (Parenthetical) - $ / shares |
Mar. 31, 2023 |
Mar. 31, 2022 |
|---|---|---|
| Statement of Financial Position [Abstract] | ||
| Preferred stock, par value | $ 1.00 | $ 1.00 |
| Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
| Preferred stock, shares outstanding | 0 | 0 |
| Common stock, par value | $ 0.50 | $ 0.50 |
| Common stock, shares authorized | 40,000,000 | 40,000,000 |
| Common stock, shares issued | 2,221,416 | 2,216,416 |
| Common stock, shares outstanding | 2,136,000 | 2,149,416 |
| Treasury stock, shares | 85,416 | 67,000 |
Nature of Operations |
12 Months Ended |
|---|---|
Mar. 31, 2023 | |
| Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
| Nature of Operations | 1. Nature of Operations
Mexco Energy Corporation (a Colorado corporation) and its wholly owned subsidiaries, Forman Energy Corporation (a New York corporation), Southwest Texas Disposal Corporation (a Texas corporation) and TBO Oil & Gas, LLC (a Texas limited liability company) (collectively, the “Company”) are engaged in the acquisition, exploration, development and production of crude oil, natural gas, condensate and natural gas liquids (“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas and Southeastern New Mexico; however, the Company owns producing properties and undeveloped acreage in fourteen states. All of the Company’s oil and gas interests are operated by others.
|
Summary of Significant Accounting Policies |
12 Months Ended |
|---|---|
Mar. 31, 2023 | |
| Accounting Policies [Abstract] | |
| Summary of Significant Accounting Policies | 2. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned subsidiaries. All significant intercompany balances and transactions associated with the consolidated operations have been eliminated.
Estimates and Assumptions. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”), management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.
Cash and Cash Equivalents. The Company considers all highly liquid debt instruments purchased with maturities of three months or less and money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally insured limits. At March 31, 2023, the Company had on deposit all of its cash and cash equivalents with three financial institutions. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk.
Accounts Receivable. Accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectibility of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on the Company’s previous loss history. The Company has not experienced any significant credit losses. For the years ended March 31, 2023 and 2022, no allowance has been made for doubtful accounts.
Oil and Gas Properties. Oil and gas properties are accounted for using the full cost method of accounting. Under this method of accounting, the costs of unsuccessful, as well as successful, acquisition, exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred. Generally, no gains or losses are recognized on the sale or disposition of oil and gas properties.
Excluded Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (“DD&A”) pool). Impairments transferred to the DD&A pool increase the DD&A rate. No costs were excluded for the years ended March 31, 2023 and 2022.
Ceiling Test. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior first day of the month 12-month period held flat for the life of production plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated DD&A. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce stockholders’ equity and reported earnings.
Depreciation, Depletion and Amortization. The depreciable base for oil and gas properties includes the sum of capitalized costs, net of accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production method.
Asset Retirement Obligations. The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using the units of production method. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations.
Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. The Company uses the present value of estimated cash flows related to the ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Income Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.
Other Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of to ten years.
Revenue Recognition - Revenue from Contracts with Customers. Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to three months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant.
Gas Balancing. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when excess takes of natural gas volumes exceed estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced). The Company does not have any significant gas imbalances.
Reclassifications. Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s presentation. These reclassifications had no effect on previously reported results of operations, retained earnings or net cash flows.
Investments. The Company accounts for investments of less than 3% in limited liability companies at cost. The Company has no control of the limited liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations.
Liquidity and Capital Resources. Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interest, non-operated properties in areas with significant development potential.
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Long-Term Debt |
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Mar. 31, 2023 | |||||||||||||||||||||||||||||||||||||||||
| Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||
| Long-Term Debt | 3. Long-Term Debt
On December 28, 2018, the Company entered into a loan agreement (the “Agreement”) with West Texas National Bank (“WTNB”), which originally provided for a credit facility of $1,000,000 with a maturity date of December 28, 2021. The Agreement has no monthly commitment reduction and a borrowing base to be evaluated annually.
On February 28, 2020, the Agreement was amended to increase the credit facility to $2,500,000, extend the maturity date to March 28, 2023 and increase the borrowing base to $1,500,000. On March 28, 2023, the Agreement was amended to extend the maturity date to March 28, 2026.
Under the Agreement, interest on the facility accrues at a rate equal to the prime rate as quoted in the Wall Street Journal plus one-half of one percent () floating daily. Interest on the outstanding amount under the Agreement is payable monthly. In addition, the Company will pay an unused commitment fee in an amount equal to one-half of one percent (.5%) times the daily average of the unadvanced amount of the commitment. The unused commitment fee is payable quarterly in arrears on the last day of each calendar quarter. As of March 31, 2023, there was $1,500,000 available for borrowing by the Company on the facility.
No principal payments are anticipated to be required through the maturity date of the credit facility, March 28, 2026. Upon closing the first amendment to the Agreement, the Company paid a loan origination fee of $2,500 and an extension fee of $3,125 plus legal and recording expenses totaling $12,266, which were also deferred over the life of the credit facility. Upon closing the second amendment to the Agreement, the Company paid a loan origination fee of $9,000 plus legal and recording expenses totaling $12,950, which were also deferred over the life of the credit facility.
Amounts borrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially all of the Company’s oil and gas properties.
The Agreement contains customary covenants for credit facilities of this type including limitations on change in control, disposition of assets, mergers and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement and requires senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratios (Senior Debt/EBITDA) less than or equal to 4.00 to 1.00 measured with respect to the four trailing fiscal quarters and minimum interest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter.
In addition, the Agreement prohibits the Company from paying cash dividends on its common stock without prior written permission of WTNB. The Company obtained written permission from WTNB prior to declaring the special dividend on April 10, 2023 as discussed in Note 14. The Agreement does not permit the Company to enter into hedge agreements covering crude oil and natural gas prices without prior WTNB approval.
There was no balance outstanding on the credit facility as of March 31, 2023. The following table is a summary of activity on the WTNB credit facility for the years ended March 31, 2023 and 2022:
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Asset Retirement Obligations |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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| Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Asset Retirement Obligations | 4. Asset Retirement Obligations
The Company’s asset retirement obligations relate to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. The fair value of a liability for an ARO is recorded in the period in which it is incurred, discounted to its present value using the credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. The ARO is included on the consolidated balance sheets with the current portion being included in the accounts payable and accrued expenses.
The following table provides a rollforward of the asset retirement obligations for fiscal years ended March 31:
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Income Taxes |
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| Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Income Taxes | 5. Income Taxes
On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, imposes a 15% corporate alternative minimum tax based on financial statement income, effective for tax years beginning after December 31, 2022. The IRA 2022 also establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases after December 31, 2022. The IRA 2022 did not impact the Company’s current year tax provision or the Company’s consolidated financial statements.
The Company files a consolidated federal income tax return and various state income tax returns. The amount of income taxes the Company records requires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions, the earliest year open to examination by U.S. federal and state income tax jurisdictions is 2018.
GAAP requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Significant components of net deferred tax assets (liabilities) at March 31 are as follows:
As of March 31, 2023, the Company has a statutory depletion carryforward of approximately $6,500,000, which does not expire. At March 31, 2023, the Company had a net operating loss carryforward for regular income tax reporting purposes of approximately $3,200,000, which will begin expiring in 2036. The Company’s ability to use some of its net operating loss carryforwards and certain other tax attributes to reduce current and future U.S. federal taxable income is subject to limitations under the Internal Revenue Code.
A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.
A reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows:
For the years ended March 31, 2023 and 2022, the Company did not have any uncertain tax positions.
While the amount of unrecognized tax benefits may change in the next 12 months, the Company does not expect any change to have a significant impact on its results of operations. The recognition of the total amount of the unrecognized tax benefits would have an impact on the effective tax rate. If these unrecognized tax benefits are disallowed, the Company will be required to pay additional taxes.
Based on the material write-downs of the carrying value of our oil and natural gas properties for the year ending March 31, 2016, we are in a net deferred tax asset position for years ending March 31, 2023 and 2022. Our deferred tax asset is $3,578 as of March 31, 2023 with a valuation amount of $3,578. We believe it is more likely than not that these deferred tax assets will not be realized. Management considers the likelihood that the Company’s net operating losses and other deferred tax attributes will be utilized prior to their expiration, if applicable. The determination to record a valuation allowance was based on management’s assessment of all available evidence, both positive and negative, supporting realizability of the Company deferred tax asset as required by applicable accounting standards. In light of those criteria for recognizing the tax benefit of deferred tax assets, the Company’s assessment resulted in application of a valuation allowance against the deferred tax asset as of March 31, 2023.
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Major Customers |
12 Months Ended |
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Mar. 31, 2023 | |
| Risks and Uncertainties [Abstract] | |
| Major Customers | 6. Major Customers
Currently, the Company operates exclusively within the United States and its revenues and operating profit are derived from the oil and gas industry. Oil and gas production is sold to various purchasers and the receivables are unsecured. Historically, the Company has not experienced significant credit losses on its oil and gas accounts and management is of the opinion that significant credit risk does not exist. Management is of the opinion that the loss of any one purchaser would not have an adverse effect on the Company’s ability to sell its oil and gas production.
In fiscal 2023, one purchaser accounted for 53% of the total operating revenues and 46% of the total oil and natural gas accounts receivable and another purchaser accounted for 8% of the total operating revenues and 21% of the total oil and natural gas accounts receivable. In fiscal 2022, one purchaser accounted for 67% of the total operating revenues and 60% of the total oil and natural gas accounts receivable.
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Oil and Natural Gas Costs |
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| Extractive Industries [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oil and Natural Gas Costs | 7. Oil and Natural Gas Costs
The costs related to the Company’s oil and natural gas activities were incurred as follows for the years ended March 31:
The Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:
DD&A amounted to $14.56 and $10.57 per BOE of production for the years ended March 31, 2023 and 2022, respectively.
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Income Per Common Share |
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| Income Per Common Share |
For the year ended March 31, 2023, shares relating to stock options were excluded from the computation of diluted net income because their inclusion would be anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $18.05 at March 31, 2023. For the year ended March 31, 2022, shares relating to stock options were excluded from the computation of diluted net income because their inclusion would be anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $8.51 at March 31, 2022.
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Stockholders’ Equity |
12 Months Ended |
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Mar. 31, 2023 | |
| Equity [Abstract] | |
| Stockholders’ Equity | 9. Stockholders’ Equity
In September 2022, the Board of Directors authorized the use of up to $250,000 to repurchase shares of the Company’s common stock for the treasury account. During the year ended March 31, 2023, the Company repurchased shares for the treasury account at an aggregate cost of $244,494, an average price of $ per share per share. There were shares of common stock repurchased for the treasury account during fiscal 2022. Subsequently, in April 2023, the Company’s Board of Directors authorized the use of up to $1,000,000 to repurchase shares of the Company’s common stock, par value, $, for the treasury account. This authorization replaced the previously authorized $ common stock repurchase program which had $5,506 remaining at the time it was replaced.
On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases after December 31, 2022. The IRA 2022 does provide for certain exceptions for repurchases of stock including an exception as long as the aggregate value of the repurchases for the tax year does not exceed $1,000,000.
On September 6, 2022, one of the Company’s directors paid the Company $30,179, representing profit on Company stock purchased within the six-month window of a previous Company stock sale. Such payment was made in accordance with Section 16(b) of the Securities Exchange Act of 1934.
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Stock-based Compensation |
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| Share-Based Payment Arrangement [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based Compensation |
In September 2019, the Company adopted the 2019 Employee Incentive Stock Plan (the “2019 Plan”). The 2019 Plan provides for the award of stock options up to shares and includes option awards as well as stock awards. Option awards are granted with the restriction of requiring payment for the shares. Stock awards are granted without restrictions and without payment by the recipient. Neither option awards nor stock awards may exceed shares granted to any one individual in any fiscal year. Stock options may be an incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan are granted at the fair market value of the common stock at the date of grant, become exercisable to the extent of % of the shares optioned on each of four anniversaries of the date of grant, expire ten years from the date of grant and are subject to forfeiture if employment terminates. The 2019 Plan expires from the date of adoption. According to the Company’s employee stock incentive plan, new shares will be issued upon the exercise of stock options and the Company can repurchase shares exercised under the plan.
During the year ended March 31, 2023, the Compensation Committee of the Board of Directors approved and the Company granted stock options. During the year ended March 31, 2022, the Compensation Committee of the Board of Directors approved and the Company granted stock options. Subsequently, in April 2023, the Compensation Committee approved and the Company granted stock options.
The plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2023 and 2022.
The Company recognized compensation expense of $ and $ related to vesting stock options in general and administrative expense in the Consolidated Statements of Operations for fiscal 2023 and 2022, respectively. The total cost related to non-vested awards not yet recognized at March 31, 2023 totals $, which is expected to be recognized over a weighted average of years.
The fair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are based on historical volatility of the Company’s stock over the contractual term of 120 months and other factors. The Company uses historical data to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. Since the Company has only declared a special one-time dividend, no dividend yield was used in the calculation. Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Binomial model.
No forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types of awards. During the year ended March 31, 2023, unvested stock options were forfeited due to the resignation of an employee. During the year ended March 31, 2022, there were stock options forfeited or expired.
During the year ended March 31, 2023, stock options covering shares were exercised with a total intrinsic value of $. The Company received proceeds of $16,700 from these exercises. During the year ended March 31, 2022, stock options covering shares were exercised with a total intrinsic value of . The Company received proceeds of $458,570 from these exercises. Subsequently, in May 2023, stock options covering shares were exercised by a former employee. The Company received proceeds of $2,962 from these exercises.
Other information pertaining to option activity was as follows during the year ended March 31:
Outstanding options at March 31, 2023 expire between August 1, 2024 and August 2032 and have exercise prices ranging from $ to $.
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Related Party Transactions |
12 Months Ended |
|---|---|
Mar. 31, 2023 | |
| Related Party Transactions [Abstract] | |
| Related Party Transactions | 11. Related Party Transactions
Related party transactions for the Company primarily relate to shared office expenditures in addition to administrative and operating expenses paid on behalf of the principal stockholder. The total billed to and reimbursed by the stockholder for the years ended March 31, 2023 and 2022 were $ and $, respectively. The principal stockholder pays for his share of the lease amount for the shared office space directly to the lessor. Amounts paid by the principal stockholder directly to the lessor for the year ending March 31, 2023 and 2022 were $15,572 and $15,775, respectively.
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Leases |
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| Leases | 12. Leases
The Company leases approximately 4,160 rentable square feet of office space from an unaffiliated third party for the corporate office located in Midland, Texas. This includes square feet of office space shared with and reimbursed by the majority shareholder. The lease does not include an option to renew and is a 36-month lease that was to expire in May 2021. In June 2020, in exchange for a reduction in rent for the months of June and July 2020, the Company agreed to a 2-month extension to its current lease agreement at the regular monthly rate extending its current lease expiration date to July 2021. In June 2021, the Company agreed to extend its current lease at a flat (unescalated) rate for 36 months. The amended lease now expires on July 31, 2024.
The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets.
Operating lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate, the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 3.75%. Significant judgement is required when determining the incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term.
The balance sheets classification of lease assets and liabilities was as follows:
Future minimum lease payments as of March 31, 2023 under non-cancellable operating leases are as follows:
Net cash paid for our operating lease for the year ended March 31, 2023 and 2022 was $42,668 and $42,237, respectively. Rent expense, less sublease income of $15,572 and $18,555, respectively, is included in general and administrative expenses.
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Oil and Gas Reserve Data (Unaudited) |
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| Extractive Industries [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oil and Gas Reserve Data (Unaudited) | 13. Oil and Gas Reserve Data (Unaudited)
The estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The estimates as of March 31, 2023 and 2022 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The services provided by Russell K. Hall and Associates, Inc. are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
The following table presents the weighted average first-day-of-the-month prices used for oil and gas reserve preparation, based upon SEC guidelines.
The Company’s total estimated proved reserves at March 31, 2023 were approximately 1.552 MBOE of which 47% was oil and natural gas liquids and 53% was natural gas.
Changes in Proved Reserves:
Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves (“PUD”) are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion within five years of the date of their initial recognition. Moreover, the Company may be required to write down its proved undeveloped reserves if the operators do not drill on the reserves within the required five-year timeframe. Such downward revisions are primarily the result of reserves written off due to the five-year limitation and the change in the timing of new development. They are primarily royalty interests on leases in Loving, Pecos and Ward Counties, Texas which are held by production and still in place to be developed in the future.
Summary of Proved Developed and Undeveloped Reserves as of March 31, 2023 and 2022:
At March 31, 2023, the Company reported estimated PUDs of 403 MBOE, which accounted for 26% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 84 new wells (234 MBOE) operated by others, 8 wells are currently being drilled with plans for 15 wells to follow in fiscal 2024, 41 wells in fiscal 2025, 16 wells in fiscal 2026 and 4 wells fiscal 2027. The cost of these projects would be funded, to the extent possible, from existing cash balances, cash flow from operations and bank borrowings. The remainder may be funded through non-core asset sales and/or sales of our common stock.
The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2023.
Progress of Converting Proved Undeveloped Reserves:
Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2023 and 2022 along with estimates of the operating costs, production taxes and future development costs necessary to produce such reserves. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.
Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company’s share of proved undeveloped properties through March 31, 2027 are $3,837,540.
Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards.
The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.
The current reporting rules require that year end reserve calculations and future cash inflows be based on the 12-month average market prices for sales of oil and gas on the first calendar day of each month during the fiscal year discounted at 10% per year and assuming continuation of existing economic conditions. The average prices used for fiscal 2023 were $92.02 per bbl of oil and $5.68 per mcf of natural gas. The average prices used for fiscal 2022 were $74.52 per bbl of oil and $4.60 per mcf of natural gas.
The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first day of the month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rate to the difference.
The basis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of proved oil and gas properties.
The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of March 31, 2023 and 2022 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
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Subsequent Events |
12 Months Ended |
|---|---|
Mar. 31, 2023 | |
| Subsequent Events [Abstract] | |
| Subsequent Events | 14. Subsequent Events
On April 10, 2023, the Company announced that its Board of Directors declared a special dividend of $ per common share to its shareholders of record at the close of business on May 1, 2023. The special dividend was paid on May 15, 2023.
In April 2023, the Company expended approximately $133,200 to participate in the drilling of 4 horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico.
In May 2023, the Company expended approximately $210,600 to complete 4 horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico that were drilled during fiscal 2023.
In June 2023, the Company received approximately $258,000 in cash from a sale of joint venture leasehold acreage and marginal producing working interest wells in Reagan County, Texas.
The Company completed a review and analysis of all events that occurred after the consolidated balance sheet date to determine if any such events must be reported and has determined that there are no other subsequent events to be disclosed. |
Summary of Significant Accounting Policies (Policies) |
12 Months Ended |
|---|---|
Mar. 31, 2023 | |
| Accounting Policies [Abstract] | |
| Principles of Consolidation | Principles of Consolidation. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned subsidiaries. All significant intercompany balances and transactions associated with the consolidated operations have been eliminated.
|
| Estimates and Assumptions | Estimates and Assumptions. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”), management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.
|
| Cash and Cash Equivalents | Cash and Cash Equivalents. The Company considers all highly liquid debt instruments purchased with maturities of three months or less and money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally insured limits. At March 31, 2023, the Company had on deposit all of its cash and cash equivalents with three financial institutions. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk.
|
| Accounts Receivable | Accounts Receivable. Accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectibility of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on the Company’s previous loss history. The Company has not experienced any significant credit losses. For the years ended March 31, 2023 and 2022, no allowance has been made for doubtful accounts.
|
| Oil and Gas Properties | Oil and Gas Properties. Oil and gas properties are accounted for using the full cost method of accounting. Under this method of accounting, the costs of unsuccessful, as well as successful, acquisition, exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred. Generally, no gains or losses are recognized on the sale or disposition of oil and gas properties.
|
| Excluded Costs | Excluded Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (“DD&A”) pool). Impairments transferred to the DD&A pool increase the DD&A rate. No costs were excluded for the years ended March 31, 2023 and 2022.
|
| Ceiling Test | Ceiling Test. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior first day of the month 12-month period held flat for the life of production plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated DD&A. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce stockholders’ equity and reported earnings.
|
| Depreciation, Depletion and Amortization | Depreciation, Depletion and Amortization. The depreciable base for oil and gas properties includes the sum of capitalized costs, net of accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production method.
|
| Asset Retirement Obligations | Asset Retirement Obligations. The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using the units of production method. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations.
Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. The Company uses the present value of estimated cash flows related to the ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset.
|
| Income Taxes | Income Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.
|
| Other Property and Equipment | Other Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of to ten years.
|
| Income Per Common Share |
|
| Revenue Recognition - Revenue from Contracts with Customers | Revenue Recognition - Revenue from Contracts with Customers. Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to three months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant.
|
| Gas Balancing | Gas Balancing. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when excess takes of natural gas volumes exceed estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced). The Company does not have any significant gas imbalances.
|
| Stock-based Compensation |
|
| Reclassifications | Reclassifications. Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s presentation. These reclassifications had no effect on previously reported results of operations, retained earnings or net cash flows.
|
| Investments | Investments. The Company accounts for investments of less than 3% in limited liability companies at cost. The Company has no control of the limited liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations.
|
| Liquidity and Capital Resources | Liquidity and Capital Resources. Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interest, non-operated properties in areas with significant development potential. |
Long-Term Debt (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Mar. 31, 2023 | |||||||||||||||||||||||||||||||||||||||||
| Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||
| Summary of Line of Credit Activity | There was no balance outstanding on the credit facility as of March 31, 2023. The following table is a summary of activity on the WTNB credit facility for the years ended March 31, 2023 and 2022:
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Asset Retirement Obligations (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Rollforward of Asset Retirement Obligations | The following table provides a rollforward of the asset retirement obligations for fiscal years ended March 31:
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Income Taxes (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Components of Net Deferred Tax Assets (Liabilities) | GAAP requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Significant components of net deferred tax assets (liabilities) at March 31 are as follows:
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| Schedule of Reconciliation of Provision for Income Taxes | A reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows:
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Oil and Natural Gas Costs (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Extractive Industries [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Cost Related to Oil and Gas Activities | The costs related to the Company’s oil and natural gas activities were incurred as follows for the years ended March 31:
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| Schedule of Aggregate Capitalized Costs Relating Oil and Gas Property Activities | The Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:
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Income Per Common Share (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Income per common share: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Reconciliation of Basic and Diluted Net Income (loss) Per Share |
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Stock-based Compensation (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Share-Based Payment Arrangement [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Summary of Grant-date Fair Value of Stock Options Granted and Assumptions Used Binomial Models |
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| Summary of Activity of Stock Options |
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| Summary of Information About Options Outstanding | Other information pertaining to option activity was as follows during the year ended March 31:
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| Summary of Information About Options Outstanding |
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Leases (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Leases | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Operating Lease Assets and Liabilities | The balance sheets classification of lease assets and liabilities was as follows:
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| Schedule of Future Minimum Lease Payments | Future minimum lease payments as of March 31, 2023 under non-cancellable operating leases are as follows:
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Oil and Gas Reserve Data (Unaudited) (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Extractive Industries [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Changes in Proved Reserve | The following table presents the weighted average first-day-of-the-month prices used for oil and gas reserve preparation, based upon SEC guidelines.
|
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| Schedule of Changes in Proved Reserve | Changes in Proved Reserves:
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| Summary of Proved Developed and Undeveloped Reserves | Summary of Proved Developed and Undeveloped Reserves as of March 31, 2023 and 2022:
|
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| Schedule of Progress of Converting Proved Undeveloped Reserves | Progress of Converting Proved Undeveloped Reserves:
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| Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves | Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
|
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| Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows to Proved Oil and Gas Reserves | Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
|
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Summary of Significant Accounting Policies (Details Narrative) - USD ($) |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Property, Plant and Equipment [Line Items] | ||
| Allowances for doubtful accounts | $ 0 | $ 0 |
| Impariment charges | $ 0 | $ 0 |
| Cost method investments, percentage description | The Company accounts for investments of less than 3% in limited liability companies at cost | |
| Office Furniture and Equipment [Member] | Minimum [Member] | ||
| Property, Plant and Equipment [Line Items] | ||
| Estimated useful lives of property and equipment | 3 years | |
| Office Furniture and Equipment [Member] | Maximum [Member] | ||
| Property, Plant and Equipment [Line Items] | ||
| Estimated useful lives of property and equipment | 10 years | |
Summary of Line of Credit Activity (Details) - USD ($) |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Debt Disclosure [Abstract] | ||
| Beginning balance | $ 1,180,000 | |
| Borrowings | 675,000 | 275,000 |
| Repayments | 675,000 | 1,455,000 |
| Ending balance | ||
Long-Term Debt (Details Narrative) - Loan Agreement [Member] - USD ($) |
12 Months Ended | ||
|---|---|---|---|
Feb. 28, 2020 |
Dec. 28, 2018 |
Mar. 31, 2023 |
|
| Collaborative Arrangement and Arrangement Other than Collaborative [Line Items] | |||
| Loan Processing Fee | $ 9,000 | ||
| Legal Fees | 12,950 | ||
| Debt instrument covenant description | The Agreement contains customary covenants for credit facilities of this type including limitations on change in control, disposition of assets, mergers and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement and requires senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratios (Senior Debt/EBITDA) less than or equal to 4.00 to 1.00 measured with respect to the four trailing fiscal quarters and minimum interest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter | ||
| West Texas National Bank [Member] | |||
| Collaborative Arrangement and Arrangement Other than Collaborative [Line Items] | |||
| Line of credit facility | $ 2,500,000 | $ 1,000,000 | |
| Line of credit facility, maturity date | Mar. 28, 2026 | Dec. 28, 2021 | |
| Line of credit, increase in borrowing base amount | $ 1,500,000 | ||
| Debt instrument rate | 0.50% | ||
| Commitment fee description | the Company will pay an unused commitment fee in an amount equal to one-half of one percent (.5%) times the daily average of the unadvanced amount of the commitment | ||
| Line of credit available for borrowing | $ 1,500,000 | ||
| Line of Credit Facility, Commitment Fee Percentage | 0.10% | ||
| Loan Processing Fee | $ 2,500 | ||
| [custom:ExtensionFees] | 3,125 | ||
| Legal Fees | $ 12,266 |
Schedule of Rollforward of Asset Retirement Obligations (Details) - USD ($) |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Asset Retirement Obligation Disclosure [Abstract] | ||
| Carrying amount of asset retirement obligations, beginning of year | $ 735,512 | $ 728,797 |
| Liabilities incurred | 23,492 | 14,333 |
| Liabilities settled | (59,260) | (36,178) |
| Accretion expense | 30,532 | 28,560 |
| Revisions | ||
| Carrying amount of asset retirement obligations, end of year | 730,276 | 735,512 |
| Less: Current portion | 20,000 | 15,000 |
| Non-Current asset retirement obligation | $ 710,276 | $ 720,512 |
Schedule of Components of Net Deferred Tax Assets (Liabilities) (Details) - USD ($) |
Mar. 31, 2023 |
Mar. 31, 2022 |
|---|---|---|
| Deferred tax assets: | ||
| Percentage depletion carryforwards | $ 1,375,131 | $ 1,117,622 |
| Deferred stock-based compensation | 22,041 | 30,094 |
| Asset retirement obligation | 153,358 | 154,458 |
| Net operating loss | 665,386 | 1,132,918 |
| Other | 11,642 | 10,263 |
| Total deferred tax assets | 2,227,558 | 2,445,355 |
| Deferred tax liabilities: | ||
| Excess financial accounting bases over tax bases of property and equipment | 2,223,980 | 1,691,865 |
| Deferred tax asset, net | 3,578 | 753,490 |
| Valuation allowance | (3,578) | (753,490) |
| Net deferred tax |
Schedule of Reconciliation of Provision for Income Taxes (Details) - USD ($) |
12 Months Ended | |||
|---|---|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|||
| Income Tax Disclosure [Abstract] | ||||
| Tax expense at federal statutory rate | [1] | $ 979,167 | $ 599,564 | |
| Statutory depletion carryforward | (257,509) | 14,730 | ||
| Change in valuation allowance | (749,912) | (504,911) | ||
| U. S. tax reform, corporate rate reduction | ||||
| Permanent differences | 28,196 | (97,349) | ||
| State income expense | 164,510 | 102,356 | ||
| Other | 58 | (12,034) | ||
| State income tax expense | $ 164,510 | $ 102,356 | ||
| Effective income tax rate | 340.00% | 350.00% | ||
| ||||
Income Taxes - Schedule of Reconciliation of Provision for Income Taxes (Details) (Parenthetical) |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Income Tax Disclosure [Abstract] | ||
| Federal income tax rate | 21.00% | 21.00% |
Income Taxes (Details Narrative) - USD ($) |
12 Months Ended | ||
|---|---|---|---|
Aug. 16, 2022 |
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Income Tax Disclosure [Abstract] | |||
| Income Tax Examination, Description | The IRA 2022, among other tax provisions, imposes a 15% corporate alternative minimum tax based on financial statement income, effective for tax years beginning after December 31, 2022. The IRA 2022 also establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases after December 31, 2022 | ||
| Net operating loss carryforward with no expiration | $ 6,500,000 | ||
| Net operating loss carryforward | $ 3,200,000 | ||
| Net operating carryforwards expiration date, description | expiring in 2036 | ||
| Amount of uncertain tax position | $ 0 | $ 0 | |
| Deferred Tax Assets, Net | 3,578 | 753,490 | |
| Deferred Tax Assets, Valuation Allowance | $ 3,578 | $ 753,490 |
Major Customers (Details Narrative) - Customer Concentration Risk [Member] |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Revenue Benchmark [Member] | One Purchaser [Member] | ||
| Concentration Risk [Line Items] | ||
| Concentration of credit risk | 53.00% | 67.00% |
| Revenue Benchmark [Member] | Two Purchaser [Member] | ||
| Concentration Risk [Line Items] | ||
| Concentration of credit risk | 8.00% | |
| Accounts Receivable [Member] | One Purchaser [Member] | ||
| Concentration Risk [Line Items] | ||
| Concentration of credit risk | 46.00% | 60.00% |
| Accounts Receivable [Member] | Two Purchaser [Member] | ||
| Concentration Risk [Line Items] | ||
| Concentration of credit risk | 21.00% | |
Schedule of Cost Related to Oil and Gas Activities (Details) - USD ($) |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Extractive Industries [Abstract] | ||
| Proved | $ 1,053,442 | $ 560,893 |
| Unproved | ||
| Exploration | ||
| Development | 4,282,499 | 1,325,560 |
| Capitalized asset retirement obligations | 23,492 | 14,333 |
| Total costs incurred for oil and gas properties | $ 5,359,433 | $ 1,900,786 |
Schedule of Aggregate Capitalized Costs Relating Oil and Gas Property Activities (Details) - USD ($) |
Mar. 31, 2023 |
Mar. 31, 2022 |
|---|---|---|
| Extractive Industries [Abstract] | ||
| Proved oil and gas properties | $ 45,391,634 | $ 40,373,741 |
| Unproved oil and gas properties: | ||
| subject to amortization | ||
| not subject to amortization | ||
| Oil and gas properties, gross | 45,391,634 | 40,373,741 |
| Less accumulated DD&A | 32,099,439 | 30,248,651 |
| Total oil and gas properties | $ 13,292,195 | $ 10,125,090 |
Oil and Natural Gas Costs (Details Narrative) - $ / shares |
Mar. 31, 2023 |
Mar. 31, 2022 |
|---|---|---|
| Extractive Industries [Abstract] | ||
| DD&A per BOE production | $ 14.56 | $ 10.57 |
Schedule of Reconciliation of Basic and Diluted Net Income (loss) Per Share (Details) - USD ($) |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Income per common share: | ||
| Net income | $ 4,662,702 | $ 2,855,066 |
| Weighted avg. common shares outstanding – basic | 2,146,491 | 2,104,896 |
| Effect of the assumed exercise of dilutive stock options | 62,172 | 53,195 |
| Weighted avg. common shares outstanding – dilutive | 2,208,663 | 2,158,091 |
| Basic | $ 2.17 | $ 1.36 |
| Diluted | $ 2.11 | $ 1.32 |
Income Per Common Share (Details Narrative) - $ / shares |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Income per common share: | ||
| Antidilutive securities excluded from computation of earnings per share | 31,000 | 31,000 |
| Anti-dilutive stock options have a weighted average exercise price | $ 18.05 | $ 8.51 |
Stockholders’ Equity (Details Narrative) - USD ($) |
12 Months Ended | ||||
|---|---|---|---|---|---|
Sep. 06, 2022 |
Mar. 31, 2023 |
Mar. 31, 2022 |
Sep. 30, 2022 |
Aug. 16, 2022 |
|
| Statement [Line Items] | |||||
| Stock authorized repurchased shares for treasury | $ 1,000,000 | ||||
| Stock repurchased during the period, shares | 0 | ||||
| Stock repurchased during the period, aggregate cost | $ 244,494 | ||||
| Share price | $ 13.28 | ||||
| Common stock par value | $ 0.50 | $ 0.50 | |||
| Common stock shares authorized | 40,000,000 | 40,000,000 | |||
| Excise tax percentage | 1.00% | ||||
| Board of Directors [Member] | |||||
| Statement [Line Items] | |||||
| Stock authorized repurchased shares for treasury | $ 5,506 | ||||
| Stock repurchased during the period, shares | 18,416 | ||||
| Stock repurchased during the period, aggregate cost | $ 244,494 | ||||
| Common stock par value | $ 0.50 | ||||
| Common stock shares authorized | 250,000 | ||||
| Director [Member] | |||||
| Statement [Line Items] | |||||
| Profit on stock sale | $ 30,179 | ||||
| Maximum [Member] | Board of Directors [Member] | |||||
| Statement [Line Items] | |||||
| Stock authorized repurchased shares for treasury | $ 1,000,000 | $ 250,000 | |||
Summary of Grant-date Fair Value of Stock Options Granted and Assumptions Used Binomial Models (Details) - $ / shares |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Share-Based Payment Arrangement [Abstract] | ||
| Grant-date fair value | $ 12.44 | $ 6.05 |
| Volatility factor | 57.30% | 65.38% |
| Dividend yield | ||
| Risk-free interest rate | 3.15% | 0.92% |
| Expected term (in years) | 6 years 3 months | 6 years 3 months |
Related Party Transactions (Details Narrative) - USD ($) |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 31, 2022 |
|
| Related Party Transaction [Line Items] | ||
| Due to related party | $ 15,572 | $ 15,775 |
| Related Party [Member] | ||
| Related Party Transaction [Line Items] | ||
| Reimbursement expenses | $ 47,055 | $ 46,595 |
Schedule of Operating Lease Assets and Liabilities (Details) - USD ($) |
Mar. 31, 2023 |
Mar. 31, 2022 |
|---|---|---|
| Leases | ||
| Operating lease right-of-use asset, beginning balance | $ 129,923 | |
| Current period amortization | (54,294) | |
| Lease amendment | ||
| Total operating lease right-of-use asset | 75,629 | $ 129,923 |
| Operating lease liability, current | 56,366 | 54,294 |
| Operating lease liability, long term | 19,263 | $ 75,629 |
| Total lease liabilities | $ 75,629 |
Schedule of Future Minimum Lease Payments (Details) - USD ($) |
Mar. 31, 2023 |
Mar. 31, 2022 |
|---|---|---|
| Leases | ||
| Fiscal Year Ended March 31, 2024 | $ 58,240 | |
| Fiscal Year Ended March 31, 2025 | 19,413 | |
| Total lease payments | 77,653 | |
| Less: imputed interest | (2,024) | |
| Operating lease liability | 75,629 | |
| Less: operating lease liability, current | (56,366) | $ (54,294) |
| Operating lease liability, long term | $ 19,263 | $ 75,629 |
Leases (Details Narrative) |
1 Months Ended | 12 Months Ended | ||
|---|---|---|---|---|
Jun. 30, 2021 |
Jun. 30, 2020 |
Mar. 31, 2023
USD ($)
ft²
|
Mar. 31, 2022
USD ($)
|
|
| Deferred Compensation Arrangement with Individual, Excluding Share-Based Payments and Postretirement Benefits [Line Items] | ||||
| Area of lease | ft² | 4,160 | |||
| Lease term | 36 months | |||
| Lease term extension, description | In June 2021, the Company agreed to extend its current lease at a flat (unescalated) rate for 36 months. The amended lease now expires on July 31, 2024 | In June 2020, in exchange for a reduction in rent for the months of June and July 2020, the Company agreed to a 2-month extension to its current lease agreement at the regular monthly rate extending its current lease expiration date to July 2021 | ||
| Lessee, operating lease, renewal term | 36 months | |||
| Lease expiration date | Jul. 31, 2024 | |||
| Incremental borrowing rate | 3.75% | |||
| Operating Lease, Payments | $ | $ 42,668 | $ 42,237 | ||
| Sublease Income | $ | $ 15,572 | $ 18,555 | ||
| Shareholder [Member] | ||||
| Deferred Compensation Arrangement with Individual, Excluding Share-Based Payments and Postretirement Benefits [Line Items] | ||||
| Area of lease | ft² | 1,112 | |||
Summary of Proved Developed and Undeveloped Reserves (Details) |
Mar. 31, 2023
Mcf
bbl
|
Mar. 31, 2022
Mcf
bbl
|
Mar. 31, 2021
Mcf
bbl
|
|---|---|---|---|
| Oil [Member] | |||
| Reserve Quantities [Line Items] | |||
| Proved Developed Reserves | bbl | 486,770 | 428,680 | 413,050 |
| Proved Undeveloped Reserves | bbl | 240,060 | 380,550 | 325,020 |
| Natural Gas [Member] | |||
| Reserve Quantities [Line Items] | |||
| Proved Developed Reserves | Mcf | 3,971,370 | 3,583,470 | 3,639,330 |
| Proved Undeveloped Reserves | Mcf | 978,010 | 1,258,210 | 956,050 |
Schedule of Progress of Converting Proved Undeveloped Reserves (Details) |
12 Months Ended |
|---|---|
|
Mar. 31, 2023
USD ($)
Boe
| |
| Extractive Industries [Abstract] | |
| PUDs, beginning of year | Boe | 590,259 |
| PUDs, beginning of year, Future Development Costs | $ | $ 6,512,956 |
| Revision of previous estimates | Boe | (89,073) |
| Revision of previous estimates, Future Development Costs | $ | $ 10,017 |
| Sales of reserves | Boe | |
| Sales of reserves, Future Development Costs | $ | |
| Conversions to PD reserves | Boe | (186,360) |
| Conversions to PD reserves, Future Development Costs | $ | $ (3,612,315) |
| Additional PUDs added | Boe | 88,239 |
| Additional PUDs added, Future Development Costs | $ | $ 926,882 |
| PUDs, end of year | Boe | 403,065 |
| PUDs, end of year, Future Development Costs | $ | $ 3,837,540 |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Details) - USD ($) |
Mar. 31, 2023 |
Mar. 31, 2022 |
Mar. 30, 2022 |
Mar. 31, 2021 |
|---|---|---|---|---|
| Extractive Industries [Abstract] | ||||
| Future cash inflows | $ 94,972,000 | $ 82,596,000 | ||
| Future production costs and taxes | (23,800,000) | (21,351,000) | ||
| Future development costs | (4,280,000) | (6,839,000) | ||
| Future income taxes | (11,284,000) | (8,586,000) | ||
| Future net cash flows | 55,608,000 | 45,820,000 | ||
| Annual 10% discount for estimated timing of cash flows | (22,793,000) | (19,900,000) | ||
| Standardized measure of discounted future net cash flows | $ 32,815,000 | $ 25,920,000 | $ 25,920,000 | $ 12,763,000 |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows to Proved Oil and Gas Reserves (Details) - USD ($) |
12 Months Ended | |
|---|---|---|
Mar. 31, 2023 |
Mar. 30, 2022 |
|
| Extractive Industries [Abstract] | ||
| Sales of oil and gas produced, net of production costs | $ (7,661,000) | $ (5,244,000) |
| Net changes in price and production costs | 8,937,000 | (16,829,000) |
| Changes in previously estimated development costs | 413,000 | (159,000) |
| Revisions of quantity estimates | (4,313,000) | (2,594,000) |
| Net change due to purchases and sales of minerals in place | 2,030,000 | 568,000 |
| Extensions and discoveries, less related costs | 3,277,000 | 5,105,000 |
| Net change in income taxes | (1,801,000) | (3,861,000) |
| Accretion of discount | 3,947,000 | 3,078,000 |
| Changes in timing of estimated cash flows and other | 2,066,000 | (565,000) |
| Changes in standardized measure | 6,895,000 | 13,157,000 |
| Standardized measure, beginning of year | 25,920,000 | 12,763,000 |
| Standardized measure, end of year | $ 32,815,000 | $ 25,920,000 |
Subsequent Events (Details Narrative) - USD ($) |
1 Months Ended | 12 Months Ended | |||||
|---|---|---|---|---|---|---|---|
Jun. 30, 2023 |
May 31, 2023 |
May 30, 2023 |
Apr. 30, 2023 |
Mar. 31, 2023 |
Mar. 31, 2022 |
May 15, 2023 |
|
| Subsequent Event [Line Items] | |||||||
| Proceeds from option exercise | $ 2,962 | $ 16,700 | $ 458,570 | ||||
| Subsequent Event [Member] | |||||||
| Subsequent Event [Line Items] | |||||||
| Special dividend | $ 0.10 | ||||||
| Subsequent Event [Member] | Wolfcamp Sand Formation [Member] | NEW MEXICO | |||||||
| Subsequent Event [Line Items] | |||||||
| Proceeds from option exercise | $ 210,600 | $ 133,200 | |||||
| Subsequent Event [Member] | Wolfcamp Sand Formation [Member] | TEXAS | |||||||
| Subsequent Event [Line Items] | |||||||
| Proceeds from option exercise | $ 258,000 | ||||||